Item 1B
Unresolved Staff Comments
None.
General Information on Facilities
The net investment of the Company in property, plant and equipment was $5.3 billion at September 30, 2015. The Exploration and Production segment comprises 39.9% of this investment, and is primarily located in California and in the Appalachian region of the United States. Approximately 51.4% of the Company's investment in net property, plant and equipment was in the Utility and Pipeline and Storage segments, whose operations are located primarily in western and central New York and northwestern Pennsylvania. The Gathering segment comprises 7.5% of the Company’s investment in net property, plant and equipment, and is located in northwestern Pennsylvania. The remaining net investment in property, plant and equipment consisted of the All Other category and Corporate operations (1.2%). During the past five years, the Company has made additions to property, plant and equipment in order to expand its exploration and production operations in the Appalachian region of the United States and to expand and improve transmission facilities for transportation customers in New York and Pennsylvania. Net property, plant and equipment has increased $1.9 billion, or 54.5%, since September 30, 2010. As part of its strategy to focus its exploration and production activities within the Appalachian region of the United States, specifically within the Marcellus Shale, the Company sold its off-shore oil and natural gas properties in the Gulf of Mexico in April 2011. The net property, plant and equipment associated with these properties was $55.4 million. The Company also sold on-shore oil and natural gas properties in its West Coast region in May 2011 with net property, plant and equipment of $8.1 million.
The Exploration and Production segment had a net investment in property, plant and equipment of $2.1 billion at September 30, 2015.
The Pipeline and Storage segment had a net investment of $1.4 billion in property, plant and equipment at September 30, 2015. Transmission pipeline represents 35% of this segment’s total net investment and includes 2,340 miles of pipeline utilized to move large volumes of gas throughout its service area. Storage facilities represent 16% of this segment’s total net investment and consist of 31 storage fields operating at a combined working gas level of 73.4 Bcf, four of which are jointly owned and operated with other interstate gas pipeline companies, and 427 miles of pipeline. Net investment in storage facilities includes $83.2 million of gas stored underground-noncurrent, representing the cost of the gas utilized to maintain pressure levels for normal operating purposes as well as gas maintained for system balancing and other purposes, including that needed for no-notice transportation service. The Pipeline and Storage segment has 34 compressor stations with 148,717 installed compressor horsepower that represent 20% of this segment’s total net investment in property, plant and equipment.
The Gathering segment had a net investment of $0.4 billion in property, plant and equipment at September 30, 2015. Gathering lines and related compressors comprise substantially all of this segment’s total net investment, including 82 miles of lines utilized to move Appalachian production (including Marcellus Shale) to various transmission pipeline receipt points. The Gathering segment has 4 compressor stations with 34,500 installed compressor horsepower.
The Utility segment had a net investment in property, plant and equipment of $1.4 billion at September 30, 2015. The net investment in its gas distribution network (including 14,816 miles of distribution pipeline) and its service connections to customers represent approximately 48% and 34%, respectively, of the Utility segment’s net investment in property, plant and equipment at September 30, 2015.
The Pipeline and Storage segments’ facilities provided the capacity to meet Supply Corporation’s 2015 peak day sendout for transportation service of 2,384 MMcf, which occurred on January 7, 2015. Withdrawals from storage of 622.3 MMcf provided approximately 26% of the requirements on that day.
Company maps are included in Exhibit 99.2 of this Form 10-K and are incorporated herein by reference.
Exploration and Production Activities
The Company is engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in California and the Appalachian region of the United States. The Company has been increasing its emphasis in the Appalachian region, primarily in the Marcellus Shale, and sold its off-shore oil and natural gas properties in the Gulf of Mexico during 2011, as mentioned above. Further discussion of oil and gas producing activities is included in Item 8, Note M - Supplementary Information for Oil and Gas Producing Activities. Note M sets forth proved developed and undeveloped reserve information for Seneca. The September 30, 2015, 2014 and 2013 reserves shown in Note M are valued using an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. The reserves were estimated by Seneca’s geologists and engineers and were audited by independent petroleum engineers from Netherland, Sewell & Associates, Inc. Note M discusses the qualifications of the Company's reservoir engineers, internal controls over the reserve estimation process and audit of the reserve estimates and changes in proved developed and undeveloped oil and natural gas reserves year over year.
Seneca’s proved developed and undeveloped natural gas reserves increased from 1,683 Bcf at September 30, 2014 to 2,142 Bcf at September 30, 2015. This increase is attributed to extensions and discoveries of 633 Bcf, partially offset by production of 140 Bcf and negative revisions of previous estimates of 34 Bcf. Total downward gas revisions of 34 Bcf were primarily a result of negative revisions due to lower gas prices of 38 Bcf primarily in the Marcellus Shale and Upper Devonian reservoirs, coupled with the removal of 38 Bcf of PUD reserves in the Marcellus Shale in Tioga County as the Company has no near term plans to develop these reserves as it is employing capital elsewhere. Partially offsetting these negative revisions were a 16 Bcf upward revision to Marcellus PUD reserves transferred to proved developed reserves and a 26 Bcf upward revision to remaining Marcellus PUD reserves.
Seneca’s proved developed and undeveloped oil reserves decreased from 38,477 Mbbl at September 30, 2014 to 33,722 Mbbl at September 30, 2015. Extensions and discoveries of 533 Mbbl were exceeded by production of 3,034 Mbbl, primarily occurring in the West Coast region, and downward revisions of previous estimates of 2,254 Mbbl. Downward revisions of 2,254 Mbbl were primarily a result of lower oil prices (1,861 Mbbl) as well as removing 279 Mbbl of PUD reserves at the North Lost Hills field in the Tulare reservoir as the Company has no near term plans to develop these reserves as it is employing capital elsewhere. On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from 1,914 Bcfe at September 30, 2014 to 2,344 Bcfe at September 30, 2015. Total revisions of previous estimates was a decrease of 48 Bcfe.
Seneca’s proved developed and undeveloped natural gas reserves increased from 1,300 Bcf at September 30, 2013 to 1,683 Bcf at September 30, 2014. This increase was attributed to extensions and discoveries of 447 Bcf, acquisitions of 34 Bcf (both primarily Marcellus Shale) and positive revisions of previous estimates of 45 Bcf which were partially offset by production of 142 Bcf. Upward performance revisions of 45 Bcf were primarily performance revisions in the Marcellus Shale and included a 20 Bcf upward revision to Marcellus PUD reserves transferred to proved developed reserves and a 13 Bcf upward revision to remaining Marcellus PUD reserves.
Seneca’s proved developed and undeveloped oil reserves decreased from 41,598 Mbbl at September 30, 2013 to 38,477 Mbbl at September 30, 2014. Extensions and discoveries of 1,539 Mbbl were exceeded by production of 3,036 Mbbl primarily occurring in the West Coast region (3,005 Mbbl), and downward revisions of previous estimates of 1,694 Mbbl. Downward revisions were primarily a result of removing 1,501 Mbbl of proved undeveloped reserves at the Midway Sunset field in the Tulare reservoir as the Company has no near term plans to develop these reserves as it is employing its capital elsewhere. On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from 1,549 Bcfe at September 30, 2013 to 1,914 Bcfe at September 30, 2014. Total revisions of previous estimates was an increase of 35 Bcfe.
At September 30, 2015, the Company’s Exploration and Production segment had delivery commitments of 2,134 Bcfe (mostly natural gas as commitments for crude oil, gasoline, butane and propane was insignificant). The Company expects to meet those commitments through proved reserves, including the future development of reserves that are currently classified as proved undeveloped reserves, the growth of proved gas reserves (which has averaged 30 percent over the past two years through the development of Seneca's large Appalachian acreage position) and (if necessary) from the purchase of natural gas and crude oil at index-related prices.
The following is a summary of certain oil and gas information taken from Seneca’s records. All monetary amounts are expressed in U.S. dollars.
Production
(1)
The Marcellus Shale fields (which exceed 15% of total reserves at September 30, 2015, 2014 and 2013) contributed 357 MMcfe, 361 MMcfe and 258 MMcfe of daily production in 2015, 2014 and 2013, respectively. The average sales price (per Mcfe) was $2.48 ($3.35 after hedging) in 2015, $3.53 ($3.47 after hedging) in 2014 and $3.49 ($4.04 after hedging) in 2013. The average lifting costs (per Mcfe) were $0.79 in 2015, $0.72 in 2014 and $0.64 in 2013.
Productive Wells
Developed and Undeveloped Acreage
As of September 30, 2015, the aggregate amount of gross undeveloped acreage expiring in the next three years and thereafter are as follows: 10,684 acres in 2016 (8,083 net acres), 12,441 acres in 2017 (8,723 net acres), 2,154 acres in 2018 (1,621 net acres) and 50,989 acres thereafter (46,845 net acres). The remaining 308,671 gross acres (295,704 net acres) represent non-expiring oil and gas rights owned by the Company. Of the acreage that is currently scheduled to expire in 2016, 2017 and 2018, Seneca has 88 Bcfe of proved undeveloped gas reserves, with 54 Bcfe subject to lease expirations in 2016 and 34 Bcfe subject to lease expirations in 2017. This total represents approximately 11% of Seneca's proved undeveloped reserves in the Marcellus Shale. Seneca intends to develop these reserves prior to the expiration of the leases and/or extend/renew as part of its management approved development plan.
Drilling Activity
Present Activities
(1)
Includes wells awaiting completion.
Item 3
Item 3
Legal Proceedings
For a discussion of various environmental and other matters, refer to Part II, Item 7, MD&A and Item 8 at Note I - Commitments and Contingencies.
Item 4
Item 4
Mine Safety Disclosures
Not Applicable.
PART II
Item 5
Item 5
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Information regarding the market for the Company’s common equity and related stockholder matters appears under Item 12 at Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, Item 8 at Note E - Capitalization and Short-Term Borrowings, and at Note L - Market for Common Stock and Related Shareholder Matters (unaudited).
On July 1, 2015, the Company issued a total of 4,200 unregistered shares of Company common stock to the seven non-employee directors of the Company then serving on the Board of Directors of the Company, 600 shares to each such director. All of these unregistered shares were issued under the Company’s 2009 Non-Employee Director Equity Compensation Plan as partial consideration for such directors’ services during the quarter ended September 30, 2015. These transactions were exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as transactions not involving a public offering.
Issuer Purchases of Equity Securities
(a)
Represents shares of common stock of the Company tendered to the Company by holders of stock options, SARs, restricted stock units or shares of restricted stock for the payment of option exercise prices or applicable withholding taxes. During the quarter ended September 30, 2015, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program.
(b)
In September 2008, the Company’s Board of Directors authorized the repurchase of eight million shares of the Company’s common stock. The repurchase program has no expiration date. The Company, however, stopped repurchasing shares after September 17, 2008. Since that time, the Company has increased its emphasis on Marcellus Shale development and pipeline expansion. As such, the Company does not anticipate repurchasing any shares in the near future.
Performance Graph
The following graph compares the Company’s common stock performance with the performance of the S&P 500 Index, the PHLX Utility Sector Index and the SIG Oil Exploration & Production Index for the period September 30, 2010 through September 30, 2015. The graph assumes that the value of the investment in the Company’s common stock and in each index was $100 on September 30, 2010 and that all dividends were reinvested.
Source: Bloomberg
The performance graph above is furnished and not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and will not be incorporated by reference into any registration statement filed under the Securities Act of 1933 unless specifically identified therein as being incorporated therein by reference. The performance graph is not soliciting material subject to Regulation 14A.
Item 6
Item 6
Selected Financial Data
Item 7
Item 7
Management’s Discussion and Analysis of Financial Condition and Results of Operations
OVERVIEW
The Company is a diversified energy company engaged principally in the production, gathering, transportation, distribution and marketing of natural gas. The Company operates an integrated business, with assets centered in western New York and Pennsylvania, being utilized for, and benefiting from, the production and transportation of natural gas from the Marcellus Shale basin. The common geographic footprint of the Company’s subsidiaries enables them to share management, labor, facilities and support services across various businesses and pursue coordinated projects designed to produce and transport natural gas from the Marcellus Shale to markets in Canada and the eastern United States. The Company also develops and produces oil reserves, primarily in California. The Company reports financial results for five business segments. Refer to Item 1, Business, for a more detailed description of each of the segments. This Item 7, MD&A, provides information concerning:
1.
The critical accounting estimates of the Company;
2.
Changes in revenues and earnings of the Company under the heading, “Results of Operations;”
3.
Operating, investing and financing cash flows under the heading “Capital Resources and Liquidity;”
4.
Off-Balance Sheet Arrangements;
5.
Contractual Obligations; and
6.
Other Matters, including: (a) 2015 and projected 2016 funding for the Company’s pension and other post-retirement benefits; (b) disclosures and tables concerning market risk sensitive instruments; (c) rate and regulatory matters in the Company’s New York, Pennsylvania and FERC-regulated jurisdictions; (d) environmental matters; and (e) new authoritative accounting and financial reporting guidance.
The information in MD&A should be read in conjunction with the Company’s financial statements in Item 8 of this report.
For the year ended September 30, 2015 compared to the year ended September 30, 2014, the Company experienced a loss of $379.4 million. The loss is driven largely by impairment charges of $1.1 billion ($650.2 million after-tax) recorded in the Exploration and Production segment during the year ended September 30, 2015. In the Company's Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Such costs are subject to a quarterly ceiling test prescribed by SEC Regulation S-X Rule 4-10 that determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. Due to significant declines in crude oil and natural gas commodity prices, the book value of the Company's oil and gas properties exceeded the ceiling at March 31, 2015, June 30, 2015 and September 30, 2015, resulting in the impairment charges mentioned above. The Company expects that the book value of its oil and gas properties will also exceed the ceiling at December 31, 2015, resulting in an additional impairment charge. For further discussion of the ceiling test and a sensitivity analysis concerning changes in crude oil and natural gas commodity prices and their impact on the ceiling test, refer to the Critical Accounting Estimates section below. For further discussion of the Company’s earnings, refer to the Results of Operations section below.
The Company continues to develop its natural gas reserves in the Marcellus Shale, a Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York. The Company controls the natural gas interests associated with approximately 790,000 net acres within the Marcellus Shale area, with a majority of the interests held in fee, carrying no royalty and no lease expirations. Natural gas proved developed and undeveloped reserves in the Appalachian region increased from 1,624 Bcf at September 30, 2014 to 2,093 Bcf at September 30, 2015. The Company has spent significant amounts of capital in this region related to the development of such reserves. For the year ended September 30, 2015, the Company’s Exploration and Production segment had capital expenditures of $500.2 million in the Appalachian region, of which $458.6 million was spent towards the development of the Marcellus Shale. The amount spent towards the development of the Marcellus Shale represented approximately 46% of the Company's capital expenditures for the year ended September 30, 2015. The Company’s fiscal 2016 estimated capital expenditures in the Exploration and Production segment’s Appalachian region are expected to be approximately $380 million. Forecasted production in the Exploration and Production segment’s Appalachian region for fiscal 2016 is expected to be in the range of 141 to 211 Bcfe, up from actual Appalachia production of 137 Bcfe in fiscal 2015.
To facilitate the flow of natural gas from the Marcellus Shale, the Company continues to expand its gathering and pipeline infrastructure in the Gathering segment and the Pipeline and Storage segment. For the year ended September 30, 2015, the Gathering segment had capital expenditures of $118.2 million and its estimated capital expenditures in fiscal 2016 are expected to be approximately $140 million. The Pipeline and Storage segment's capital expenditures for the year ended September 30, 2015 were $230.2 million and its estimated capital expenditures in fiscal 2016 are expected to be approximately $525 million. The amount spent towards the development of gathering and pipeline infrastructure in fiscal 2015 represented approximately 35% of the Company's capital expenditures.
The well stimulation technology referred to as hydraulic fracturing used in conjunction with horizontal drilling continues to be debated. In Pennsylvania, where the Company is focusing its Marcellus Shale development efforts, the permitting and regulatory processes seem to strike a balance between the environmental concerns associated with hydraulic fracturing and the benefits of increased natural gas production. The potential for increased state or federal regulation of hydraulic fracturing could impact future costs of drilling in the Marcellus Shale and lead to operational delays or restrictions. There is also the risk that drilling could be prohibited on certain acreage that is prospective for the Marcellus Shale. Please refer to the Risk Factors section above for further discussion.
From a capital resources perspective, in June 2015, the Company issued $450.0 million of 5.20% notes due in July 2025. The notes were issued to enhance the Company's liquidity position and reduce short-term debt. Under the Company's existing indenture covenants, given the significant impairments recorded during the year ended September 30, 2015, the Company is precluded from issuing additional long-term unsecured indebtedness during fiscal 2016. If the Company experiences additional significant impairments of its oil and gas properties in
the first or subsequent quarters of fiscal 2016, the Company expects to continue to be precluded from issuing incremental long-term debt into the first or subsequent quarters of fiscal 2017. However, the Company expects that it could borrow under its credit facilities. In addition, the 1974 indenture would not preclude the Company from issuing new long-term debt to replace maturing long-term debt. On September 30, 2015, the Company entered into a Second Amended and Restated Credit Agreement (the "Credit Agreement") that amends and restates a five-year, $750 million unsecured committed revolving credit facility obtained by the Company in December 2014. The Credit Agreement provides a $750.0 million multi-year unsecured committed revolving credit facility through December 5, 2019, plus a $500.0 million 364-day unsecured committed revolving credit facility through September 29, 2016. With respect to borrowings under the multi-year facility, the Company is permitted (but not required) to elect a maturity date that is 364 days after the date of borrowing. The Credit Agreement includes an option for the Company to request increases in the aggregate multi-year commitments to an amount not to exceed $850.0 million, subject to certain terms and conditions.
CRITICAL ACCOUNTING ESTIMATES
The Company has prepared its consolidated financial statements in conformity with GAAP. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. In the event estimates or assumptions prove to be different from actual results, adjustments are made in subsequent periods to reflect more current information. The following is a summary of the Company’s most critical accounting estimates, which are defined as those estimates whereby judgments or uncertainties could affect the application of accounting policies and materially different amounts could be reported under different conditions or using different assumptions. For a complete discussion of the Company’s significant accounting policies, refer to Item 8 at Note A - Summary of Significant Accounting Policies.
Oil and Gas Exploration and Development Costs. In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this accounting methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center.
Proved reserves are estimated quantities of reserves that, based on geologic and engineering data, appear with reasonable certainty to be producible under existing economic and operating conditions. Such estimates of proved reserves are inherently imprecise and may be subject to substantial revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. The estimates involved in determining proved reserves are critical accounting estimates because they serve as the basis over which capitalized costs are depleted under the full cost method of accounting (on a units-of-production basis). Unproved properties are excluded from the depletion calculation until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.
In addition to depletion under the units-of-production method, proved reserves are a major component in the SEC full cost ceiling test. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future
expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The estimates of future production and future expenditures are based on internal budgets that reflect planned production from current wells and expenditures necessary to sustain such future production. The amount of the ceiling can fluctuate significantly from period to period because of additions to or subtractions from proved reserves and significant fluctuations in oil and gas prices. The ceiling is then compared to the capitalized cost of oil and gas properties less accumulated depletion and related deferred income taxes. If the capitalized costs of oil and gas properties less accumulated depletion and related deferred taxes exceeds the ceiling at the end of any fiscal quarter, a non-cash impairment charge must be recorded to write down the book value of the reserves to their present value. This non-cash impairment cannot be reversed at a later date if the ceiling increases. It should also be noted that a non-cash impairment to write down the book value of the reserves to their present value in any given period causes a reduction in future depletion expense. The book value of the Company’s oil and gas properties exceeded the ceiling at September 30, 2015 as well as June 30, 2015 and March 31, 2015, resulting in cumulative impairment charges of $1.1 billion ($650.2 million after-tax) for 2015. The 12-month average of the first day of the month price for crude oil for each month during 2015, based on posted Midway Sunset prices, was $54.54 per Bbl. The 12-month average of the first day of the month price for natural gas for each month during 2015, based on the quoted Henry Hub spot price for natural gas, was $3.06 per MMBtu. (Note - Because actual pricing of the Company’s various producing properties varies depending on their location and hedging, the actual various prices received for such production is utilized to calculate the ceiling, rather than the Midway Sunset and Henry Hub prices, which are only indicative of 12-month average prices for 2015.) If natural gas average prices used in the ceiling test calculation at September 30, 2015 had been $0.25 per MMBtu lower, the book value of the Company’s oil and gas properties would have exceeded the ceiling by approximately $378.1 million (after-tax), which would have resulted in an additional impairment charge of $137.3 million (after-tax) at September 30, 2015. If crude oil average prices used in the ceiling test calculation at September 30, 2015 had been $5 per Bbl lower, the book value of the Company’s oil and gas properties would have exceeded the ceiling by approximately $281.6 million (after-tax), which would have resulted in an additional impairment charge of $40.8 million (after-tax) at September 30, 2015. If both natural gas and crude oil average prices used in the ceiling test calculation at September 30, 2015 were lower by $0.25 per MMBtu and $5 per Bbl, respectively, the book value of the Company’s oil and gas properties would have exceeded the ceiling by approximately $418.9 million (after-tax), which would have resulted in an additional impairment charge of $178.1 million (after-tax) at September 30, 2015. These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation including, among others, changes in reserve quantities and future cost estimates. Looking ahead, the first day of the month Midway Sunset price for crude oil in October 2015 was $39.67 per Bbl. The first day of the month Henry Hub spot price for natural gas in October 2015 was $2.48 per MMBtu. Given these October prices, the potential that prices could stay at this level in future months, and the expected loss of significantly higher oil and gas prices from the 12-month average that will be used in the ceiling test at December 31, 2015, the Company expects to experience an additional significant ceiling test impairment in that quarter (the first quarter of fiscal 2016). Depending upon the movement of oil and natural gas prices, it is possible that the Company may experience additional impairment charges in the second or subsequent quarters of fiscal 2016 as well.
It is difficult to predict what factors could lead to future impairments under the SEC’s full cost ceiling test. As discussed above, fluctuations in or subtractions from proved reserves and significant fluctuations in oil and gas prices have an impact on the amount of the ceiling at any point in time.
In accordance with the current authoritative guidance for asset retirement obligations, the Company records an asset retirement obligation for plugging and abandonment costs associated with the Exploration and Production segment’s crude oil and natural gas wells and capitalizes such costs in property, plant and equipment (i.e. the full cost pool). Under the current authoritative guidance for asset retirement obligations, since plugging and abandonment costs are already included in the full cost pool, the units-of-production depletion calculation excludes from the depletion base any estimate of future plugging and abandonment costs that are already recorded in the full cost pool.
As discussed above, the full cost method of accounting provides a ceiling to the amount of costs that can be capitalized in the full cost pool. In accordance with current authoritative guidance, the future cash outflows
associated with plugging and abandoning wells are excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling calculation.
Regulation. The Company is subject to regulation by certain state and federal authorities. The Company, in its Utility and Pipeline and Storage segments, has accounting policies which conform to the FASB authoritative guidance regarding accounting for certain types of regulations, and which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting principles for certain types of rate-regulated activities provide that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheet and included in the income statement for the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item. For further discussion of the Company’s regulatory assets and liabilities, refer to Item 8 at Note C - Regulatory Matters.
Accounting for Derivative Financial Instruments. The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil in its Exploration and Production and Energy Marketing segments. These instruments are categorized as price swap agreements and futures contracts. In accordance with the authoritative guidance for derivative instruments and hedging activities, the Company primarily accounts for these instruments as effective cash flow hedges or fair value hedges. In addition, the Company also enters into foreign exchange forward contracts to manage the risk of currency fluctuations associated with transportation costs denominated in Canadian currency in the Exploration and Production segment. These instruments are accounted for as cash flow hedges. Gains or losses associated with the derivative financial instruments that are accounted for as cash flow or fair value hedges are matched with gains or losses resulting from the underlying physical transaction that is being hedged. To the extent that such derivative financial instruments would ever be deemed to be ineffective based on effectiveness testing, mark-to-market gains or losses from such derivative financial instruments would be recognized in the income statement without regard to an underlying physical transaction. Refer to the “Market Risk Sensitive Instruments” section below for further discussion of the Company’s derivative financial instruments and refer to Item 8 at Note F- Fair Value Measurements for discussion of the determination of fair value for derivative financial instruments.
Pension and Other Post-Retirement Benefits. The amounts reported in the Company’s financial statements related to its pension and other post-retirement benefits are determined on an actuarial basis, which uses many assumptions in the calculation of such amounts. These assumptions include the discount rate, the expected return on plan assets, the rate of compensation increase and, for other post-retirement benefits, the expected annual rate of increase in per capita cost of covered medical and prescription benefits. The Company utilizes the Mercer Yield Curve Above Mean Model to determine the discount rate. The yield curve is a spot rate yield curve that provides a zero-coupon interest rate for each year into the future. Each year’s anticipated benefit payments are discounted at the associated spot interest rate back to the measurement date. The discount rate is then determined based on the spot interest rate that results in the same present value when applied to the same anticipated benefit payments. In determining the spot rates, the model will exclude coupon interest rates that are in the lower 50th percentile based on the assumption that the Company would not utilize more expensive (i.e. lower yield) instruments to settle its liabilities. The expected return on plan assets assumption used by the Company reflects the anticipated long-term rate of return on the plan’s current and future assets. The Company utilizes historical investment data, projected capital market conditions, and the plan’s target asset class and investment manager allocations to set the assumption regarding the expected return on plan assets. Changes in actuarial assumptions and actuarial experience, including deviations between actual versus expected return on plan assets, could have a material impact on the amount of pension and post-retirement benefit costs and funding requirements experienced by the Company. However, the Company expects to recover a substantial portion of its net periodic pension and other post-retirement benefit costs attributable to employees in its Utility and Pipeline and Storage segments in accordance with the applicable
regulatory commission authorization, subject to applicable accounting requirements for rate-regulated activities, as discussed above under “Regulation.”
Changes in actuarial assumptions and actuarial experience could also have an impact on the benefit obligation and the funded status related to the Company’s pension and other post-retirement benefits and could impact the Company’s equity. For example, the discount rate used to determine benefit obligations of the Company's other post-retirement benefits changed from 4.25% in 2014 to 4.50% in 2015. The change in the discount rate from 2014 to 2015 reduced the accumulated post-retirement benefit obligation by $14.3 million. While the discount rate used to determine benefit obligations of the Retirement Plan did not change from 2014 to 2015, the discount rate was changed from 4.75% in 2013 to 4.25% in 2014. The change in the discount rate from 2013 to 2014 increased the Retirement Plan projected benefit obligation by $53.7 million. Other examples include actual versus expected return on plan assets, which has an impact on the funded status of the plans, and actual versus expected benefit payments, which has an impact on the pension plan projected benefit obligation and the accumulated post-retirement benefit obligation. For 2015, the actual return on plan assets was lower than the expected return, which resulted in a decrease to the funded status of the Retirement Plan ($73.0 million) as well as a decrease to the funded status of the VEBA trusts and 401(h) accounts ($33.6 million). The actual versus expected benefit payments for 2015 caused a decrease of $2.6 million to the accumulated post-retirement benefit obligation. In calculating the projected benefit obligation for the Retirement Plan and the accumulated post-retirement obligation, the actuary takes into account the average remaining service life of active participants. The average remaining service life of active participants is 7 years for the Retirement Plan and 6 years for those eligible for other post-retirement benefits. For further discussion of the Company’s pension and other post-retirement benefits, refer to Other Matters in this Item 7, which includes a discussion of funding for the current year, and to Item 8 at Note H - Retirement Plan and Other Post Retirement Benefits.
RESULTS OF OPERATIONS
EARNINGS
2015 Compared with 2014
The Company experienced a loss of $379.4 million in 2015 compared with earnings of $299.4 million in 2014. The decrease in earnings is primarily the result of a loss recognized in the Exploration and Production segment. Lower earnings in the Gathering segment and Utility segment, as well as losses in the Corporate category and All Other category, also contributed to the decrease. Higher earnings in the Pipeline and Storage segment and the Energy Marketing segment partially offset these decreases. In the discussion that follows, all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted. Earnings were impacted by the following events in 2015 and 2014:
2015 Events
•
Non-cash impairment charges of $1.1 billion ($650.2 million after tax) recorded during 2015 for the Exploration and Production segment’s oil and gas producing properties.
•
A $5.2 million reversal of stock-based compensation expense related to performance based restricted stock units since performance conditions, which do not include any market conditions, are not expected to be met. The $5.2 million was allocated across each of the segments as well as the All Other and Corporate category.
2014 Event
•
A $3.6 million death benefit gain on life insurance proceeds recorded in the Corporate category.
2014 Compared with 2013
The Company’s earnings were $299.4 million in 2014 compared with earnings of $260.0 million in 2013. The increase in earnings of $39.4 million is primarily a result of higher earnings in the Exploration and Production
segment, Pipeline and Storage segment, Gathering segment and Energy Marketing segment. Lower earnings in the Utility segment and a higher loss in the Corporate category slightly offset these increases. Earnings were impacted by the 2014 event discussed above and the following event in 2013:
2013 Event
•
A $4.9 million refund provision recorded in the Utility segment related to various issues raised in Distribution Corporation’s rate proceeding in New York.
Earnings (Loss) by Segment
EXPLORATION AND PRODUCTION
Revenues
Exploration and Production Operating Revenues
Production
Average Prices
(1)
Refer to further discussion of hedging activities below under “Market Risk Sensitive Instruments” and in Note G - Financial Instruments in Item 8 of this report.
2015 Compared with 2014
Operating revenues for the Exploration and Production segment decreased $110.7 million in 2015 as compared with 2014. Gas production revenue after hedging decreased $34.8 million primarily due to a $0.18 per Mcf decrease in the weighted average price of gas after hedging and a decrease in production due to temporary pricing-related curtailments. Oil production revenue after hedging decreased $76.5 million due to a $25.19 per Bbl decrease in the weighted average price of oil after hedging as production was largely flat. In addition, processing plant revenue decreased $1.9 million, largely due to a decrease in the price of natural gas liquids and other price and volume fluctuations. Partially offsetting these decreases was a $2.7 million increase in other revenue. This was largely due to a $3.7 million positive variance in mark-to-market adjustments related to hedging ineffectiveness and the reversal of a gas imbalance liability ($0.6 million) related to offshore properties no longer owned by the Exploration and Production segment, partially offset by the impact from the receipt of settlement proceeds in fiscal 2014 related to former insurance policies ($1.9 million) that did not recur in the current year.
Refer to further discussion of derivative financial instruments in the “Market Risk Sensitive Instruments” section that follows. Refer to the tables above for production and price information.
2014 Compared with 2013
Operating revenues for the Exploration and Production segment increased $101.2 million in 2014 as compared with 2013. Gas production revenue after hedging increased $81.8 million primarily due to production increases in the Appalachian division. The increase in Appalachian production was primarily due to increased development within the Marcellus Shale formation, primarily in Lycoming County, Pennsylvania. This was partially offset by a $0.54 per Mcf decrease in the weighted average price of gas after hedging. Oil production revenue after hedging increased $12.0 million due to an increase in production, which was partially offset by a $2.66 per Bbl decrease in the weighted average price of oil after hedging. The increase in crude oil production was largely due to increased development in the East Coalinga, Sespe and South Midway Sunset fields in California. The increase in other revenue ($7.0 million) was largely due to a $3.6 million positive variance in mark-to-market charges related to hedging ineffectiveness, settlement proceeds received in 2014 related to former insurance policies ($1.9 million) and the non-recurrence of a royalty adjustment (including interest) recorded in 2013 ($1.8 million).
Earnings
2015 Compared with 2014
The Exploration and Production segment’s loss for 2015 was $557.0 million, compared with earnings of $121.6 million for 2014, a decrease of $678.6 million. The main drivers of the decrease were the aforementioned impairment charge ($650.2 million), lower crude oil prices after hedging ($49.7 million), lower natural gas prices after hedging ($16.3 million), lower natural gas production ($6.3 million), the impact of the non-recurrence of settlement proceeds on former insurance policies recorded in the prior year ($1.3 million), higher interest expense ($2.9 million), higher production costs ($1.5 million) and higher operating expenses ($1.4 million). The increase in production costs was largely attributable to higher transportation costs associated with production volumes transported by Midstream Corporation. The increase in interest expense was largely due to the Exploration and Production segment's share of the Company's $450 million long-term debt issuance in June 2015. The increase in operating expenses was largely due to an increase in professional services and personnel costs, partially offset by a reversal of stock-based compensation expense for certain performance based restricted stock unit awards since performance conditions are not expected to be met. These decreases in earnings were partially offset by the impact of lower depletion expense ($36.7 million), lower income tax expense ($11.8 million) and the impact of mark-to-market adjustments ($2.4 million). The decrease in depletion expense is due to the impact of impairment charges recognized in the second and third quarters of 2015, a decrease in production due to pricing-related curtailments discussed above, and an increase in reserves achieved with lower finding and development costs per Mcfe (due to increased operating efficiencies). The decrease in income tax expense was largely due to an increase in firm transportation of natural gas to Canadian delivery points, which decreased the effective tax rate used in the calculation of deferred tax expense ($3.0 million) combined with other deferred tax adjustments that reduced Seneca's deferred income tax liability by $6.2 million. The decrease in income taxes was partially offset by the non-recurrence of a favorable settlement with a taxing authority that occurred in fiscal 2014.
2014 Compared with 2013
The Exploration and Production segment’s earnings for 2014 were $121.6 million, compared with earnings of $115.4 million for 2013, an increase of $6.2 million. The main drivers of the increase were higher natural gas production ($102.8 million), higher crude oil production ($13.1 million) and lower income taxes ($11.2 million). In addition, the earnings impact of the increase in other revenues ($4.6 million) also contributed to the increase in earnings, as discussed above. The decrease in income taxes was largely due to an increase in firm transportation of natural gas to Canadian delivery points, which decreased the effective tax rate used in the calculation of deferred tax expense. These earnings increases were partially offset by the earnings impact of higher depletion expense ($34.3 million), lower natural gas prices after hedging ($49.7 million), higher production costs ($30.1 million), higher general, administrative and other expense ($2.7 million), higher interest expense ($1.6 million), higher property and other taxes ($2.3 million) and lower crude oil prices after hedging ($5.3 million). The increase in depletion expense is primarily due to increased Appalachian natural gas production (primarily in the Marcellus Shale formation). The increase in production costs was largely attributable to higher transportation costs. The increase in general, administrative and other expense was largely due to an increase in personnel costs and the accrual of plugging and abandonment costs associated with offshore properties no longer owned by the Exploration
and Production segment. The increase in interest expense was attributable to an increase in the weighted average amount of debt due to the Exploration and Production segment’s share of the Company’s $500 million long-term debt issuance in February 2013.
PIPELINE AND STORAGE
Revenues
Pipeline and Storage Operating Revenues
Pipeline and Storage Throughput - (MMcf)
2015 Compared with 2014
Operating revenues for the Pipeline and Storage segment increased $6.9 million in 2015 as compared with 2014. The increase was primarily due to an increase in transportation revenues of $7.0 million. The increase in transportation revenues was largely due to demand charges for transportation service from Supply Corporation’s Mercer Expansion Project, which was placed in service in November 2014. The addition of new firm contracts for transportation service on Supply Corporation's system also contributed to the increase in transportation revenues.
Transportation volume increased by 14.1 Bcf in 2015 as compared with 2014. The increase in transportation volume primarily reflects the results of the ongoing pricing basis differentials in the Appalachian region in which customers are flowing more natural gas to higher priced markets. The addition of a new contract for interruptible transportation also contributed to the increase in transportation volume. Volume fluctuations, other than those caused by the addition or deletion of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.
2014 Compared with 2013
Operating revenues for the Pipeline and Storage segment increased $16.8 million in 2014 as compared with 2013. The increase was primarily due to an increase in transportation revenues of $17.9 million slightly offset by a decrease in storage revenues of $0.7 million. The increase in transportation revenues was largely due to demand and commodity charges on new contracts for transportation service on Supply Corporation’s Northern Access expansion project, which was placed fully in service in January 2013, Supply Corporation’s Line N 2012 Expansion Project, which was placed fully in service in November 2012 and Supply Corporation's Line N 2013 Project, which
was placed in service in November 2013. In addition, the increase in transportation revenues was due to additional demand charges associated with the full-ramp up of a transportation contract for an anchor shipper on Empire's Tioga County Extension Project as well as additional commodity charges associated with that contract due to higher throughput flowing through a secondary receipt point. These projects provide pipeline capacity for Marcellus Shale production. Also contributing to the increase in transportation revenues was additional non-expansion revenue as a result of new short-term contracts for both Empire and Supply Corporation and new contracts for transportation service from an Open Season Supply Corporation held near the end of fiscal 2013. Partially offsetting these increases was a decrease in storage revenues due to a decline in demand charges as a result of contract restructuring.
Transportation volume increased by 156.2 Bcf in 2014 as compared with 2013. The large increase in transportation volume primarily reflects the impact of the above mentioned expansion projects being placed in service and new contracts for transportation service. The increase was enhanced by weather that was significantly colder than the prior year and colder than normal.
Earnings
2015 Compared with 2014
The Pipeline and Storage segment’s earnings in 2015 were $80.4 million, an increase of $2.8 million when compared with earnings of $77.6 million in 2014. The increase in earnings is primarily due to the earnings impact of higher transportation revenues of $4.6 million, as discussed above, combined with an increase in the allowance for funds used during construction (equity component) of $2.5 million. The increase in the allowance for funds used during construction is mainly due to capital costs incurred during the year ended September 30, 2015 related to various expansion projects currently under construction. These earnings increases were partially offset by higher operating expenses ($2.0 million), an increase in depreciation expense ($1.0 million), an increase in property taxes ($0.9 million) and higher interest expense ($0.8 million). The increase in operating expenses primarily reflects an increase in compressor maintenance costs, an increase in expense related to the reserve for preliminary project costs, an increase in regulatory commission expense and increased personnel costs offset partially by the reversal of stock-based compensation expense for certain performance based restricted stock unit awards since performance conditions are not expected to be met. The increase in depreciation expense was attributable to incremental depreciation expense related to projects that were placed in service within the last year. The increase in property taxes was attributable to various expansion projects constructed over the last few years. The increase in interest expense was largely due to Supply Corporation's share of the Company's $450 million long-term debt issuance in June 2015.
2014 Compared with 2013
The Pipeline and Storage segment’s earnings in 2014 were $77.6 million, an increase of $14.4 million when compared with earnings of $63.2 million in 2013. The increase in earnings was primarily due to the earnings impact of higher transportation revenues of $11.7 million, as discussed above, combined with lower operating expenses ($6.3 million). The decrease in operating expenses primarily reflected lower pension and other post-retirement benefit costs and a decrease in the reserve for preliminary project costs offset partially by higher pipeline integrity program expenses. These earnings increases were partially offset by an increase in depreciation expense ($1.0 million), higher property taxes ($0.9 million), a decrease in the allowance for funds used during construction (equity component) of $0.4 million, higher income taxes ($0.5 million) and the earnings impact of lower storage revenue ($0.4 million), as discussed above. The increase in depreciation expense was attributable to incremental depreciation expense related to the projects that were placed in service during fiscal 2014. The increase in property taxes was primarily due to the addition of new plant. The decrease in the allowance for funds used during construction was mainly due to Supply Corporation’s Line N 2012 Expansion Project and Supply Corporation’s Northern Access expansion project, which were under construction in the first quarter of fiscal 2013 and were placed in service during fiscal 2013. The increase in income taxes was a result of higher state taxes combined with a reduction in benefits associated with the tax sharing agreement with affiliated companies.
GATHERING
Revenues
Gathering Operating Revenues
Gathering Volume - (MMcf)
2015 Compared with 2014
Operating revenues for the Gathering segment increased $6.6 million in 2015 as compared with 2014. This increase was due to an increase in gathering revenues driven by higher gathering rates coupled with a 0.9 Bcf increase in gathered volume. The overall increase in gathered volume was largely due to a 15.4 Bcf increase in gathered volume on Midstream Corporation’s Clermont Gathering System (Clermont), which was placed in service in July 2014, and a 1.6 Bcf increase in gathered volume on Midstream Corporation’s Trout Run Gathering System (Trout Run) where the increase in production during the first two quarters of the fiscal year more than offset the impact of low natural gas price related production curtailments experienced in the last two quarters of the fiscal year. The increases in gathered volume were largely offset by a 14.8 Bcf decrease in gathered volume on Midstream Corporation's Covington Gathering System (Covington), a 1.0 Bcf decrease in gathered volume on Midstream Corporation's Mt. Jewett Gathering System (Mt. Jewett) and a 0.3 Bcf decrease in gathered volume on Midstream Corporation's Tionesta Gathering System (Tionesta). Most of these decreases in gathered volume are attributable to a decrease in Seneca's Marcellus Shale production largely due to the impact of low natural gas prices, which caused Seneca to curtail production.
2014 Compared with 2013
Operating revenues for the Gathering segment increased $35.8 million in 2014 as compared with 2013. This increase was largely due to an increase in gathering revenues driven by a 45.3 Bcf increase in gathered volume combined with higher gathering rates. The overall increase in gathered volume was largely due to a 40.7 Bcf increase in gathered volume on Trout Run and a 4.5 Bcf increase in gathered volume on Clermont. Most of the increase in gathered volume was attributable to an increase in Seneca's Marcellus Shale production, primarily in Lycoming County, Pennsylvania.
Earnings
2015 Compared with 2014
The Gathering segment’s earnings in 2015 were $31.8 million, a decrease of $0.9 million when compared with earnings of $32.7 million in 2014. The decrease in earnings is mainly due to the earnings impact of higher depreciation expense ($3.1 million), higher operating expenses ($1.1 million) and higher income tax expense ($1.0 million). These earnings increases were partially offset by higher gathering revenues ($4.4 million). The growth of Trout Run and Clermont is primarily responsible for the revenue and operating expense variations. During the quarter ended March 31, 2015, the Company recorded long-lived asset impairment charges ($1.0 million) related
to its gathering facilities at Tionesta. This impairment, combined with greater plant balances, led to an increase in depreciation expense. The increase in income tax expense is due to higher state income taxes and the impact of the provision-to-return adjustments.
2014 Compared with 2013
The Gathering segment’s earnings in 2014 were $32.7 million, an increase of $19.4 million when compared with earnings of $13.3 million in 2013. The increase in earnings was mainly due to the earnings impact of higher gathering revenues ($23.5 million) and lower interest expense ($0.4 million). These earnings increases were partially offset by higher income tax expense ($1.9 million), higher depreciation expense ($1.4 million) and higher operating expenses ($1.0 million). The significant growth of Trout Run was primarily responsible for the revenue, depreciation expense and operating expense variations. The increase in income tax expense was largely due to higher state taxes. The decrease in interest expense was largely due to an increase in capitalized interest, which more than offset the impact of an increase in the weighted average amount of debt due to the Gathering segment’s share of the $500 million long-term debt issuance in February 2013.
UTILITY
Revenues
Utility Operating Revenues
Utility Throughput - million cubic feet (MMcf)
Degree Days
(1)
Percents compare actual 2015 degree days to normal degree days and actual 2015 degree days to actual 2014 degree days.
(2)
Percents compare actual 2014 degree days to normal degree days and actual 2014 degree days to actual 2013 degree days.
(3)
Percents compare actual 2013 degree days to normal degree days and actual 2013 degree days to actual 2012 degree days.
2015 Compared with 2014
Operating revenues for the Utility segment decreased $133.4 million in 2015 compared with 2014. This decrease largely resulted from a $127.9 million decrease in retail gas sales revenues. In addition, there was a $7.9 million decrease in off-system sales and a $7.9 million decrease in transportation revenues. These were partially offset by a $10.3 million increase in other operating revenues. The increase in other operating revenues was largely due to a regulatory adjustment recorded during 2015 to recognize an under-collection from customers of a New York State regulatory assessment, a 2015 reversal of a portion of a 2014 accrual for an estimated sharing refund provision in New York, and an increase in capacity release revenues. As a result of a colder than normal calendar 2013/2014 winter season, the demand for pipeline capacity increased as pipeline capacity release contracts for Distribution Corporation’s calendar 2014/2015 winter season were being executed. This increase in demand resulted in higher capacity release rates for Distribution Corporation in 2015 compared to 2014, thus resulting in higher capacity release revenues.
The $127.9 million decrease in retail gas sales revenues was largely a result of a decrease in the cost of gas sold (per Mcf) coupled with lower volumes due to slightly warmer weather than the prior year. The $7.9 million decrease in transportation revenues was primarily due to a 2.2 Bcf decrease in transportation throughput due to slightly warmer weather than the prior year. The $7.9 million decrease in off-system sales is due to lower volumes as market conditions reduced the opportunity for off-system gas sales.
2014 Compared with 2013
Operating revenues for the Utility segment increased $103.3 million in 2014 compared with 2013. This increase largely resulted from an $85.5 million increase in retail gas sales revenues and a $14.9 million increase in transportation revenue. In addition, there was an $8.2 million increase in other operating revenues. These were partially offset by a $5.3 million decrease in off-system sales (due to lower volume). The decrease in off-system sales volume was due to the Utility segment’s greater utilization of pipeline capacity in order to reliably meet the increased demand for its retail gas brought on by colder weather experienced during the winter of fiscal 2014. Due to profit sharing with retail customers, the margins resulting from off-system sales were minimal.
The $85.5 million increase in retail gas sales revenues was largely a function of higher volume (8.1 Bcf) due to colder weather. The $14.9 million increase in transportation revenues was primarily due to an 11.8 Bcf increase in transportation throughput, largely the result of colder weather compared to the prior period and the migration of customers from retail sales to transportation services. The $8.2 million increase in other operating revenues was
largely due to the non-recurrence of a $7.5 million refund provision recorded during fiscal 2013 related to various issues raised in a New York rate proceeding. During 2014, the Utility segment recorded an earnings share adjustment pursuant to the settlement resulting from that rate proceeding ($2.5 million reduction to revenues). However, this was largely offset by a 2014 true-up of regulatory asset balances associated with insurance proceeds on site remediation claims ($2.3 million).
Purchased Gas
The cost of purchased gas is the Company’s single largest operating expense. Annual variations in purchased gas costs are attributed directly to changes in gas sales volume, the price of gas purchased and the operation of purchased gas adjustment clauses. Distribution Corporation recorded $307.7 million, $446.9 million and $362.3 million of Purchased Gas expense during 2015, 2014 and 2013, respectively. Under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation is not allowed to profit from fluctuations in gas costs. Purchased gas expense recorded on the consolidated income statement matches the revenues collected from customers, a component of Operating Revenues on the consolidated income statement. Under mechanisms approved by the NYPSC in New York and the PaPUC in Pennsylvania, any difference between actual purchased gas costs and what has been collected from the customer is deferred on the consolidated balance sheet as either an asset, Unrecovered Purchased Gas Costs, or a liability, Amounts Payable to Customers. These deferrals are subsequently collected from the customer or passed back to the customer, subject to review by the NYPSC and the PaPUC. Absent disallowance of full recovery of Distribution Corporation’s purchased gas costs, such costs do not impact the profitability of the Company. Purchased gas costs impact cash flow from operations due to the timing of recovery of such costs versus the actual purchased gas costs incurred during a particular period. Distribution Corporation’s purchased gas adjustment clauses seek to mitigate this impact by adjusting revenues on either a quarterly or monthly basis.
Distribution Corporation contracts for long-term firm transportation capacity with Supply Corporation, Empire and seven other upstream pipeline companies, and for storage service with Supply Corporation and two other upstream companies. Distribution Corporation utilizes long-term and spot gas supply contracts with various producers and marketers to satisfy purchase requirements. Additional discussion of the Utility segment’s gas purchases appears under the heading “Sources and Availability of Raw Materials” in Item 1.
Earnings
2015 Compared with 2014
The Utility segment’s earnings in 2015 were $63.3 million, a decrease of $0.8 million when compared with earnings of $64.1 million in 2014. The decrease in earnings is largely attributable to an increase in operating expenses ($5.8 million), an increase in depreciation expense ($1.3 million) and the impact of slightly warmer weather in fiscal 2015 compared to fiscal 2014 ($0.6 million). The increase in operating expenses is largely attributable to costs associated with the planned replacement of the Utility segment’s legacy mainframe systems, partially offset by the reversal of stock-based compensation expense for certain performance based restricted stock unit awards since performance conditions are not expected to be met. The increase in depreciation expense is due to an increase in plant balances in fiscal 2015 compared to fiscal 2014. These earnings decreases were partially offset by a $6.2 million increase in regulatory adjustments (discussed above) and a $0.9 million increase in capacity release revenues (discussed above).
The impact of weather variations on earnings in the Utility segment’s New York rate jurisdiction is mitigated by that jurisdiction’s weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segment’s New York customers. For 2015, the WNC reduced earnings by approximately $2.5 million as the weather was colder than normal. In 2014, the WNC reduced earnings by approximately $3.0 million as the weather was colder than normal.
2014 Compared with 2013
The Utility segment’s earnings in 2014 were $64.1 million, a decrease of $1.6 million when compared with earnings of $65.7 million in 2013. The decrease in earnings was largely attributable to an increase in operating expenses ($9.1 million), an increase in income tax expense ($2.4 million), the impact of an earnings sharing adjustment ($1.6 million) and an increase in property and other taxes ($0.8 million). The increase in operating expenses was largely attributable to increased costs associated with defined benefit and defined contribution retirement plans as a result of a recent settlement with the NYPSC and an increase in bad debt expense. The increase in income tax expense was largely due to higher state income taxes and the reversal of tax expense that occurred in 2013 (as a result of a favorable tax settlement), which did not recur in 2014. The increase in property and other taxes was largely due to increases in FICA, school, town and county taxes. These earnings decreases were partially offset by the impact of colder weather in Pennsylvania ($5.8 million), the positive earnings impact of the non-recurrence of the refund provision recorded in fiscal 2013 ($4.9 million), a true-up of regulatory asset balances associated with a NYPSC settlement concerning insurance proceeds on site remediation claims ($1.5 million) and the earnings impact of lower interest expense ($0.9 million). The decrease in interest expense was due to a decrease in the weighted average amount of debt outstanding due to the Utility segment’s share of the Company’s $250 million of notes that matured in March 2013.
ENERGY MARKETING
Revenues
Energy Marketing Operating Revenues
Energy Marketing Volume
2015 Compared with 2014
Operating revenues for the Energy Marketing segment decreased $112.4 million in 2015 as compared with 2014. The decrease is primarily due to a decline in gas sales revenue due to a lower average price of natural gas period over period and a decrease in volume sold to retail customers.
2014 Compared with 2013
Operating revenues for the Energy Marketing segment increased $59.8 million in 2014 as compared with 2013. The increase reflects an increase in gas sales revenue due to a higher average price of natural gas period over period and an increase in volume sold to retail customers as a result of colder weather. Effective with the first quarter of 2014, the Energy Marketing segment began recording unbilled revenue. Operating revenues for the year ended September 30, 2014 include an $8.5 million accrual for unbilled revenue while operating revenues for the year ended September 30, 2013 do not include such an accrual. The volume associated with unbilled revenue at September 30, 2014 was 2,122 MMcf.
Earnings
2015 Compared with 2014
The Energy Marketing segment’s earnings in 2015 were $7.8 million, an increase of $1.2 million when compared with earnings of $6.6 million in 2014. This increase in earnings was largely attributable to higher margin of $1.4 million. The increase in margin largely reflects a reduction in pipeline capacity reservation charges due to the turn back of certain storage and transportation capacity, higher average margins per Mcf, and an increase in the benefit the Energy Marketing segment realized from its contracts for storage capacity. These increases were partially offset by slightly lower margin associated with unbilled revenue. The Energy Marketing segment began recording unbilled revenue and related gas costs during the quarter ended December 31, 2013. Prior to that quarter, Energy Marketing segment revenues and related purchased gas costs had been recorded when billed, resulting in a one-month lag. As a result of eliminating the one-month lag, revenues and related gas costs for the year ended September 30, 2014 reflected thirteen months of activity whereas the revenue and related gas costs for the year ended September 30, 2015 reflect twelve months of activity.
2014 Compared with 2013
The Energy Marketing segment’s earnings in 2014 were $6.6 million, an increase of $2.0 million when compared with earnings of $4.6 million in 2013. This increase in earnings was largely attributable to higher margin of $2.2 million, which primarily reflects the positive impact on margin from the increase in volume sold to retail customers due to colder weather during 2014 combined with improved average margin per Mcf. These earnings increases were partially offset by a decline in the benefit the Energy Marketing segment realized from its contracts for storage capacity. To a lesser extent, margin was also positively impacted by the recording of unbilled revenues and related gas costs at September 30, 2014. The impact of this change for the year ended September 30, 2014 was to increase operating revenues and margin by $8.5 million and $0.6 million, respectively. Management has determined that the impact of not recording unbilled revenue and related gas costs was immaterial in all prior periods.
ALL OTHER AND CORPORATE OPERATIONS
All Other and Corporate operations primarily includes the operations of Seneca’s Northeast Division and corporate operations. Seneca’s Northeast Division markets timber from its New York and Pennsylvania land holdings.
Earnings
2015 Compared with 2014
All Other and Corporate operations recorded a loss of $5.7 million in 2015, which was $2.6 million higher than the loss of $3.1 million in 2014. The increase in loss is primarily due to the non-recurrence of a $3.6 million death benefit gain on life insurance proceeds recognized during the quarter ended March 31, 2014, which was recorded in Other Income. A $0.8 million decrease in margin from the sale of standing timber (including certain timber stumpage tracts by Seneca’s land and timber division) decreased earnings further. These decreases were offset partially by lower income tax expense of $1.2 million (primarily due to consolidated tax sharing) and lower operating expenses of $1.1 million (largely due to the reversal of stock-based compensation expense for certain performance based restricted stock unit awards since performance conditions are not expected to be met).
2014 Compared with 2013
All Other and Corporate operations recorded a loss of $3.1 million in 2014, which was $0.9 million higher than the loss of $2.2 million in 2013. The increase in loss was primarily due to higher income tax expense of $4.7 million (primarily due to consolidated tax sharing and an adjustment for an intercompany deferred tax reallocation recorded in 2013 that did not recur in 2014) and higher property, franchise and other taxes of $0.7 million (largely due to a reduction in franchise taxes recorded in 2013 that did not recur in 2014). These increases were offset partially by a $3.6 million death benefit gain on life insurance policies that was recorded in 2014. In addition, earnings were increased by an increase in income from unconsolidated subsidiaries of $0.4 million.
INTEREST CHARGES
Although most of the variances in Interest Charges are discussed in the earnings discussion by segment above, the following is a summary on a consolidated basis (amounts below are pre-tax amounts):
Interest on long-term debt increased $5.7 million in 2015 as compared to 2014. This increase is due to additional long-term debt that was issued in fiscal 2015. The Company issued $450 million of 5.20% notes in June 2015. This was partially offset by the impact of an increase in capitalized interest (mostly in Midstream Corporation), which decreased interest expense for the year ended September 30, 2015 as compared to the year ended September 30, 2014.
Interest on long-term debt decreased $0.1 million in 2014 as compared to 2013. This decrease is due to an increase in capitalized interest (mostly in Midstream Corporation) for the year ended September 30, 2014 as compared to the year ended September 30, 2013. This was partially offset by the impact of a higher average amount of long-term debt outstanding (partially offset by a decrease in the weighted average interest on such debt). The Company issued $500 million of 3.75% notes in February 2013 and repaid $250 million of 5.25% notes that matured in March 2013.
CAPITAL RESOURCES AND LIQUIDITY
The primary sources and uses of cash during the last three years are summarized in the following condensed statement of cash flows:
OPERATING CASH FLOW
Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, impairment of oil and gas producing properties, deferred income taxes and stock-based compensation.
Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from year to year because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Utility segment’s New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire.
Cash provided by operating activities in the Exploration and Production segment may vary from year to year as a result of changes in the commodity prices of natural gas and crude oil as well as changes in production. The Company uses various derivative financial instruments, including price swap agreements and futures contracts in an attempt to manage this energy commodity price risk.
Net cash provided by operating activities totaled $853.6 million in 2015, a decrease of $55.8 million compared with the $909.4 million provided by operating activities in 2014. The decrease in cash provided by operating activities reflects lower cash provided by operating activities in the Exploration and Production segment. The decrease is partially offset by the increase in cash provided by operating activities in the Utility segment, Pipeline and Storage segment and Gathering segment. The decrease in the Exploration and Production segment is primarily due to lower cash receipts from crude oil and natural gas production as a result of lower crude oil and natural gas prices. The increase in the Utility segment is primarily due to the timing of gas cost recovery and the timing of receivable collections. The increase in the Gathering segment is primarily a result of an increase in Seneca’s Marcellus Shale production, which has resulted in higher gathering revenues at the Trout Run and Clermont gathering systems. Lastly, the increase in the Pipeline and Storage segment is due to higher cash receipts from transportation revenues as a result of expansion projects coming on-line.
Net cash provided by operating activities totaled $909.4 million in 2014, an increase of $170.8 million compared with the $738.6 million provided by operating activities in 2013. The increase in cash provided by operating activities reflects higher cash provided by operating activities in the Exploration and Production segment, Gathering segment and Corporate category. The increase in the Exploration and Production segment is primarily due to higher cash receipts from natural gas production in the Appalachian region, specifically development in the Marcellus Shale formation. The increase in the Gathering segment is due to an increase in gathering revenues from Midstream Corporation's Trout Run Gathering System and Midstream Corporation's Clermont Gathering System. Lastly, the increase in the Corporate category is primarily due to the receipt of life insurance proceeds.
INVESTING CASH FLOW
Expenditures for Long-Lived Assets
The Company’s expenditures for long-lived assets, including non-cash capital expenditures, totaled $1.0 billion, $969.9 million and $717.1 million in 2015, 2014 and 2013, respectively. The table below presents these expenditures:
(1)
2015 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $46.2 million, $33.9 million, $22.4 million and $16.5 million, respectively, of non-cash capital expenditures.
(2)
2014 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $80.1 million, $28.1 million, $20.1 million and $8.3 million, respectively, of non-cash capital expenditures.
(3)
2013 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $58.5 million, $5.6 million, $6.7 million and $10.3 million, respectively, of non-cash capital expenditures.
Exploration and Production
In 2015, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures and included approximately $500.2 million for the Appalachian region (including $458.6 million in the Marcellus Shale area) and $57.1 million for the West Coast region. These amounts included approximately $161.8 million spent to develop proved undeveloped reserves.
In 2014, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures and included approximately $519.9 million for the Appalachian region (including $502.9 million in the Marcellus Shale area) and $82.8 million for the West Coast region. These amounts included approximately $179.9 million spent to develop proved undeveloped reserves.
In 2013, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures and included approximately $428.5 million for the Appalachian region (including $393.3 million in the Marcellus Shale area) and $104.6 million for the West Coast region. These amounts included approximately $148.5 million spent to develop proved undeveloped reserves.
Pipeline and Storage
The majority of the Pipeline and Storage segment’s capital expenditures for 2015 were mainly for expenditures related to Supply Corporation's Westside Expansion and Modernization Project ($63.0 million), Empire and Supply Corporation's Tuscarora Lateral Project ($53.7 million), Supply Corporation's Northern Access 2015 Project ($40.4 million), Supply Corporation's Northern Access 2016 Project ($5.9 million) and Supply Corporation's Mercer Expansion Project ($5.4 million), as discussed below. In addition, the Pipeline and Storage segment capital expenditures for 2015 also include additions, improvements and replacements to this segment’s transmission and gas storage systems.
The majority of the Pipeline and Storage segment’s capital expenditures for 2014 were related to additions, improvements, and replacements to this segment’s transmission and gas storage systems. In addition, the Pipeline and Storage segment capital expenditures for 2014 included expenditures related to Supply Corporation’s Mercer Expansion Project ($27.0 million), Supply Corporation’s Northern Access 2015 project ($11.1 million) and Supply Corporation’s Westside Expansion and Modernization Project ($4.8 million), as discussed below.
The majority of the Pipeline and Storage segment’s capital expenditures for 2013 were related to additions, improvements, and replacements to this segment’s transmission and gas storage systems. In addition, the Pipeline and Storage segment capital expenditures for 2013 included expenditures for the construction of Supply Corporation’s Northern Access expansion project ($14.5 million), Supply Corporation’s Line N 2012 Expansion Project ($4.2 million), Supply Corporation’s Line N 2013 Project ($2.8 million) and Supply Corporation’s Mercer Expansion Project ($0.7 million).
Gathering
The majority of the Gathering segment’s capital expenditures for 2015 were for the construction of Midstream Corporation’s Clermont Gathering System ($117.3 million), as discussed below.
The majority of the Gathering segment’s capital expenditures for 2014 were for the construction of Midstream Corporation’s Clermont Gathering System ($95.2 million) and to build compressor stations on Midstream Corporation’s Trout Run Gathering System ($32.9 million). In addition, the Gathering segment capital expenditures for 2014 included expenditures for the expansion of Midstream Corporation's Covington Gathering System in Tioga County, Pennsylvania ($4.6 million).
The majority of the Gathering segment’s capital expenditures for 2013 were related to the expansion of Midstream Corporation’s Trout Run Gathering System ($48.0 million).
Utility
The majority of the Utility segment’s capital expenditures for 2015, 2014 and 2013 were made for replacement of mains and main extensions and for the replacement of service lines. The capital expenditures for 2015, 2014 and 2013 included $18.4 million, $15.6 million and $9.1 million, respectively, related to the replacement of the Utility segment’s customer information system, as discussed below.
Estimated Capital Expenditures
The Company’s estimated capital expenditures for the next three years are:
(1)
Includes estimated expenditures for the years ended September 30, 2016, 2017 and 2018 of approximately $166 million, $185 million and $114 million, respectively, to develop proved undeveloped reserves. The Company is committed to developing its proved undeveloped reserves within five years as required by the SEC’s final rule on Modernization of Oil and Gas Reporting.
Exploration and Production
Estimated capital expenditures in 2016 for the Exploration and Production segment include approximately $380 million for the Appalachian region and $45 million for the West Coast region.
Estimated capital expenditures in 2017 for the Exploration and Production segment include approximately $430 million for the Appalachian region and $60 million for the West Coast region.
Estimated capital expenditures in 2018 for the Exploration and Production segment include approximately $445 million for the Appalachian region and $75 million for the West Coast region.
Pipeline and Storage
Capital expenditures for the Pipeline and Storage segment in 2016 through 2018 are expected to include: construction of new pipeline and compressor stations to support expansion projects, the replacement of transmission and storage lines, the reconditioning of storage wells and improvements of compressor stations. Expansion projects are discussed below.
In light of the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia - specifically in the Marcellus and Utica Shale producing areas - Supply Corporation and Empire are actively pursuing several expansion projects and paying for preliminary survey and investigation costs, which are initially recorded as Deferred Charges on the Consolidated Balance Sheet. An offsetting reserve is established as those preliminary survey and investigation costs are incurred, which reduces the Deferred Charges balance and increases Operation and Maintenance Expense on the Consolidated Statement of Income. The Company reviews all projects on a quarterly basis, and if it is determined that it is highly probable that the project will be built, the reserve is reversed. This reversal reduces Operation and Maintenance Expense and reestablishes the original balance in Deferred Charges. After the reversal of the reserve, the amounts remain in Deferred Charges until such time as
capital expenditures for the project have been incurred and activities that are necessary to get the construction project ready for its intended use are in progress. At that point, the balance is transferred from Deferred Charges to Construction Work in Progress, a component of Property, Plant and Equipment on the Consolidated Balance Sheet. As of September 30, 2015, the total amount reserved for the Pipeline and Storage segment’s preliminary survey and investigation costs was $7.7 million.
Supply Corporation and Empire are moving forward with, or have recently completed, several projects designed to move anticipated Marcellus and Utica production gas to other interstate pipelines and to on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems. Projects where the Company has begun to make significant investments of preliminary survey and investigation costs and/or where shipper agreements have been executed are described below.
In 2011, Supply Corporation concluded an Open Season to increase its capability to move gas north on its Line N system and deliver gas to a new interconnection with Tennessee Gas Pipeline (“TGP”) at Mercer, Pennsylvania, a pooling point recently established at Tennessee’s Station 219 (“Mercer Expansion Project”). Supply Corporation executed a service agreement with Range Resources ("Range") for 105,000 Dth per day, all of the project capacity, for service which began November 1, 2014. The cost estimate is $34.2 million, of which $30.1 million is for expansion and $4.1 million is for replacement. Supply Corporation constructed the required 3,550 horsepower of compression at Mercer, and replaced 2.08 miles of 24” pipeline, both under its FERC blanket certificate authorization. As of September 30, 2015, approximately $33.1 million has been spent on the Mercer Expansion Project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2015.
On January 18, 2013, Supply Corporation concluded an Open Season to further increase its capacity to move gas north and south on its Line N system to Texas Eastern Transmission, LP (“TETCO”) at Holbrook and TGP at Mercer (“Westside Expansion and Modernization Project”). Supply Corporation received its FERC 7(c) certificate on March 2, 2015 and executed two service agreements (Range and Seneca) for all 175,000 Dth per day of project capacity. Partial service for Range began on September 8, 2015 with full service beginning for Range on October 16, 2015 and for Seneca on November 1, 2015. The Westside Expansion and Modernization Project facilities include the replacement of approximately 23.3 miles of 20” pipe with 24” pipe and the addition of 3,550 horsepower of compression at Mercer. The cost estimate is $86.0 million, of which $44.9 million is related to expansion and the remainder is for replacement. As of September 30, 2015, approximately $67.9 million has been capitalized as Construction Work in Progress for the Westside Expansion and Modernization Project. The remaining expenditures are expected to be spent in fiscal 2016 and are included as Pipeline and Storage estimated capital expenditures in the table above.
Supply Corporation and TGP have jointly developed a project that combines expansions on both pipeline systems, providing a seamless transportation path from TGP’s 300 Line in the Marcellus fairway to the TransCanada Pipeline delivery point at Niagara. Supply Corporation has offered 140,000 Dth per day of capacity on its system to TGP under a lease, from its Ellisburg Station for redelivery to TGP in East Eden, New York (“Northern Access 2015”). The project provides Seneca Resources, TGP’s anchor shipper, with an outlet to premium Dawn-indexed markets in Canada, for Seneca Resources' Clermont Area Marcellus production. The Northern Access 2015 project involves the construction of a new 15,400 horsepower compressor station in Hinsdale, New York and a 7,700 horsepower addition to its compressor station in Concord, New York, for service that commenced on an interim basis for 40,000 Dth per day on November 1, 2015, and is expected to be fully operational by December 1, 2015. Supply Corporation and TGP received their FERC 7(c) certificates on February 27, 2015 and have executed the Capacity Lease agreement. The cost estimate for the Northern Access 2015 project is $67.5 million. As of September 30, 2015, approximately $51.5 million has been capitalized as Construction Work in Progress for the Northern Access 2015 project. The remaining expenditures expected to be spent are included in Pipeline and Storage estimated capital expenditures in the table above.
Supply Corporation and Empire have been working with Seneca Resources to develop a project which would move significant prospective Marcellus production from Seneca Resources' Western Development Area at Clermont to an Empire interconnection with TransCanada Pipeline at Chippawa (“Northern Access 2016”). Similar to the goal of the Northern Access 2015 project, the separate and distinct Northern Access 2016 project would provide
an outlet to premium Dawn-indexed markets in Canada and to the TGP line serving the U.S. Northeast, all with a target in-service date in late calendar year 2016. The Northern Access 2016 project involves the construction of approximately 98.5 miles of largely 24” pipeline and approximately 27,500 horsepower of compression on the two systems. The preliminary cost estimate for the Northern Access 2016 project is $455 million. Supply Corporation, Empire and Seneca Resources executed anchor shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa and 140,000 Dth per day of firm transportation capacity to a new interconnection with TGP's 200 Line on this project. On July 24, 2014, Supply Corporation and Empire initiated the FERC NEPA Pre-filing process on this project and both parties filed a joint FERC 7(b) and 7(c) application in early March 2015 and amended that application on November 2, 2015. As of September 30, 2015, approximately $15.1 million has been spent on the Northern Access 2016 project, including $9.2 million that has been spent to study the project. The Company has determined it is highly probable that the project will be built. Accordingly, previous reserves have been reversed and this $9.2 million of project costs has been reestablished as a Deferred Charge on the Consolidated Balance Sheet. The remaining $5.9 million spent on the project has been capitalized as Construction Work in Progress. The remainder of the preliminary cost estimate expected to be spent on this project is included as Pipeline and Storage estimated capital expenditures in the table above.
On November 21, 2014, Supply Corporation concluded an Open Season for an expansion of its Line D pipeline (“Line D Expansion”) that is intended to allow growing on-system markets to avail themselves of economical gas supply on the TGP 300 line, at an existing interconnect at Lamont, Pennsylvania, and provide increased capacity into the Erie, Pennsylvania market area. Following negotiations with prospective shippers, Supply Corporation executed five precedent agreements for a total of 77,500 Dth per day for terms of ten years. The project involves construction of a new 4,152 horsepower Keelor Compressor Station and modifications to the Roystone and Bowen compressor stations at an estimated capital cost of approximately $23 million. The project will also provide system modernization benefits. Supply Corporation plans to seek authorization for this project under its FERC blanket certificate. The target in-service date is November 1, 2016. As of September 30, 2015, less than $0.1 million has been spent to study the Line D Expansion project, all of which has been included in preliminary survey and investigation charges and has been fully reserved for at September 30, 2015.
On August 12, 2013, Empire concluded an Open Season, offering for the first time no-notice transportation and storage services to new and existing shippers on the Empire pipeline system. Empire and Rochester Gas & Electric (“RG&E”), Empire’s largest LDC connected market, executed a precedent agreement to convert all 172,500 Dth per day of its standard firm transportation services to no-notice service, including 3.3 Bcf of no-notice storage service. The new services will provide RG&E with a superior flexible delivery service with daily and seasonal load balancing capabilities and greater access to Marcellus supplies. In addition, Empire executed a precedent agreement with New York State Electric and Gas for 14,816 Dth per day of transportation capacity and a third agreement with Distribution Corporation for the remaining 34,500 Dth per day of project capacity, providing both LDCs with increased access to Marcellus supplies. Empire has constructed a 17.2 mile, 12" and 16" pipeline and an interconnection between Empire’s pipeline system and Supply Corporation’s system at Tuscarora, New York. Empire is also modifying its Oakfield compressor station and Supply Corporation is constructing approximately 1,380 horsepower of compression at its Tuscarora compressor station (“Tuscarora Lateral Project”). Supply Corporation concluded an Open Season and has awarded to Empire the necessary storage services under a lease agreement. Empire and Supply Corporation began the FERC pre-filing process on April 12, 2013, and both companies filed their FERC 7(c) applications in March 2014. Empire and Supply Corporation received a FERC certificate on March 10, 2015. Both parties have executed the Capacity Lease, Empire executed service agreements with all three of its project shippers, and service began November 1, 2015. The cost estimate for the Tuscarora Lateral Project is $60.0 million. As of September 30, 2015, approximately $55.5 million has been capitalized as Construction Work in Progress for the Tuscarora Lateral Project. The remaining expenditures are expected to be spent in fiscal 2016 and are included in Pipeline and Storage estimated capital expenditures in the table above.
Empire is developing an expansion of its system, and began an Open Season, that would allow for the transportation of approximately 300,000 Dth per day of additional Marcellus supplies from Millennium Pipeline at Corning, from Supply Corporation at Tuscarora, or from new interconnections in Tioga County, Pennsylvania, to TransCanada Pipeline and the TGP 200 Line (“Empire North Project”). The preliminary cost estimate for the Empire North Project is at least $150 million depending on requested receipt points. As of September 30, 2015,
approximately $0.3 million has been spent to study this project, all of which has been included in preliminary survey and investigation charges and has been fully reserved for at September 30, 2015.
Gathering
The majority of the Gathering segment capital expenditures in 2016 through 2018 are expected to be for construction and expansion of gathering systems, as discussed below.
NFG Midstream Clermont, LLC, a wholly owned subsidiary of Midstream Corporation, is building an extensive gathering system with compression in the Pennsylvania counties of McKean, Elk and Cameron. The preliminary cost estimate for the continued buildout is anticipated to be in the range of $250 million to $500 million. As of September 30, 2015, approximately $216.5 million has been spent on the Clermont Gathering System, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2015.
NFG Midstream Trout Run, LLC, a wholly owned subsidiary of Midstream Corporation, continues to develop its Trout Run Gathering System in Lycoming County, Pennsylvania. The Trout Run Gathering System was initially placed in service in May 2012. The current system consists of approximately 40 miles of backbone and in-field gathering pipelines and two compressor stations. Estimated capital expenditures in 2016 through 2018 include anticipated expenditures in the range of $20 million to $50 million for the continued expansion of the Trout Run Gathering System. As of September 30, 2015, the Company has spent approximately $162.7 million in costs related to this project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2015.
Utility
Capital expenditures for the Utility segment in 2016 through 2018 are expected to be concentrated in the areas of main and service line improvements and replacements and, to a lesser extent, the purchase of new equipment. Estimated capital expenditures in the Utility segment for 2016 through 2018 also include amounts for the planned replacement of the Utility segment’s legacy mainframe systems. This includes estimated capital expenditures in 2016 of $13.6 million related to the replacement of the customer information system, which is scheduled to be placed in service in the spring of 2016. Estimated capital expenditures for the replacement of other legacy mainframe systems amount to $1.5 million for 2016, $2.1 million for 2017 and $0.4 million for 2018.
Project Funding
The Company has been financing the Pipeline and Storage segment and Gathering segment projects mentioned above, as well as the Exploration and Production segment capital expenditures, with cash from operations and both short and long-term borrowings. In addition, the Company issued additional long-term debt in June 2015 to enhance its liquidity position, including the reduction of short-term debt. Going forward, while the Company expects to use cash on hand and cash from operations as the first means of financing these projects, the Company may issue short-term debt as necessary during fiscal 2016 to help meet its capital expenditures needs. The level of short-term borrowings will depend upon the amounts of cash provided by operations, which, in turn, will likely be impacted by natural gas and crude oil prices combined with production from existing wells. As disclosed above, the Company is precluded from issuing new long-term debt throughout fiscal 2016 as a means of financing projects.
The Company continuously evaluates capital expenditures and potential investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive oil and gas properties, natural gas storage facilities and the expansion of natural gas transmission line capacities. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s other business segments depends, to a large degree, upon market conditions.
FINANCING CASH FLOW
Consolidated short-term debt decreased $85.6 million when comparing the balance sheet at September 30, 2015 to the balance sheet at September 30, 2014. The maximum amount of short-term debt outstanding during the year ended September 30, 2015 was $260.8 million. The Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. At September 30, 2015, the Company did not have any outstanding commercial paper or short-term notes payable to banks.
On December 5, 2014, the Company entered into an Amended and Restated Credit Agreement with a syndicate of 14 banks. The agreement replaced the Company's previous $750.0 million committed credit facility with a substantially similar facility totaling $750.0 million. On September 30, 2015, the Company entered into a Second Amended and Restated Credit Agreement (Credit Agreement) with a syndicate of the same 14 banks. This Credit Agreement provides a $750.0 million multi-year unsecured committed revolving credit facility through December 5, 2019, plus a $500.0 million 364-day unsecured committed revolving credit facility through September 29, 2016. The Company also has a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under the uncommitted lines of credit are made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines.
The total amount available to be issued under the Company’s commercial paper program is $500.0 million. The commercial paper program is backed by the Credit Agreement, which provides that the Company's debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter through December 5, 2019. At September 30, 2015, the Company’s debt to capitalization ratio (as calculated under the facility) was .51. The constraints specified in the Credit Agreement would have permitted an additional $1.67 billion in short-term and/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded .65.
If a downgrade in any of the Company’s credit ratings were to occur, access to the commercial paper markets might not be possible. However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources, including cash provided by operations.
The Credit Agreement contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of September 30, 2015, the Company did not have any debt outstanding under the Credit Agreement.
On June 25, 2015, the Company issued $450.0 million of 5.20% notes due July 15, 2025. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $444.6 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of a change in control and a ratings downgrade to a rating below investment grade. The proceeds of this debt issuance were used for general corporate purposes, including the reduction of short-term debt.
On February 15, 2013, the Company issued $500.0 million of 3.75% notes due March 1, 2023. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $495.4 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal
amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. The proceeds of this debt issuance were used to refund the $250.0 million of 5.25% notes that matured in March 2013, as well as for general corporate purposes, including the reduction of short-term debt.
None of the Company’s long-term debt at September 30, 2015 and 2014 had a maturity date within the following twelve-month period.
The Company’s embedded cost of long-term debt was 5.53% and 5.61% at September 30, 2015 and September 30, 2014, respectively. Refer to “Interest Rate Risk” in this Item for a more detailed breakdown of the Company’s embedded cost of long-term debt.
Under the Company’s existing indenture covenants, at September 30, 2015, the Company is precluded from issuing additional long-term unsecured indebtedness during fiscal 2016 as a result of impairments of its oil and gas properties recognized during the year ended September 30, 2015, as discussed above. The 1974 indenture would not preclude the Company from issuing new indebtedness to replace maturing debt. If the Company experiences additional significant impairments of its oil and gas properties in the first or subsequent quarters of fiscal 2016, the Company, under its 1974 indenture, expects to continue to be precluded from issuing incremental long-term debt into the first or subsequent quarters of fiscal 2017. However, the Company expects that it could borrow under its credit facilities. The Company's present liquidity position is believed to be adequate to satisfy known demands. Please refer to the Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test.
The Company’s 1974 indenture pursuant to which $99.0 million (or 4.7%) of the Company’s long-term debt (as of September 30, 2015) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.
OFF-BALANCE SHEET ARRANGEMENTS
The Company has entered into certain off-balance sheet financing arrangements. These financing arrangements are primarily operating leases. The Company’s consolidated subsidiaries have operating leases, the majority of which are with the Exploration and Production segment and Corporate operations, having a remaining lease commitment of approximately $44.8 million. These leases have been entered into for the use of compressors, drilling rigs, buildings, meters and other items and are accounted for as operating leases.
CONTRACTUAL OBLIGATIONS
The following table summarizes the Company’s expected future contractual cash obligations as of September 30, 2015, and the twelve-month periods over which they occur:
(1)
Refer to Note E - Capitalization and Short-Term Borrowings, as well as the table under Interest Rate Risk in the Market Risk Sensitive Instruments section below, for the amounts excluding interest expense.
(2)
Gas prices are variable based on the NYMEX prices adjusted for basis.
(3)
Transportation service contractual obligations include the following precedent agreements executed by the Exploration and Production segment for transportation of Appalachian gas: $10.8 million for 2016, $35.2 million for 2017, $34.3 million for 2018, $45.0 million for 2019, $46.9 million for 2020 and $718.7 million thereafter.
The Company has other long-term obligations recorded on its Consolidated Balance Sheets that are not reflected in the table above. Such long-term obligations include pension and other post-retirement liabilities, asset retirement obligations, deferred income tax liabilities, various regulatory liabilities, derivative financial instrument liabilities and other deferred credits (the majority of which consist of liabilities for non-qualified benefit plans, deferred compensation liabilities, environmental liabilities and workers compensation liabilities).
The Company has made certain other guarantees on behalf of its subsidiaries. The guarantees relate primarily to: (i) obligations under derivative financial instruments, which are included on the Consolidated Balance Sheets in accordance with the authoritative guidance (see Item 7, MD&A under the heading “Critical Accounting Estimates - Accounting for Derivative Financial Instruments”); (ii) NFR obligations to purchase gas or to purchase gas transportation/storage services where the amounts due on those obligations each month are included on the Consolidated Balance Sheets as a current liability; and (iii) other obligations which are reflected on the Consolidated Balance Sheets. The Company believes that the likelihood it would be required to make payments under the guarantees is remote, and therefore has not included them in the table above.
OTHER MATTERS
In addition to the environmental and other matters discussed in this Item 7 and in Item 8 at Note I - Commitments and Contingencies, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows
in the period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.
The Company has a tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan). The Company has been making contributions to the Retirement Plan over the last several years and anticipates that it will continue making contributions to the Retirement Plan. During 2015, the Company contributed $36.2 million to the Retirement Plan. The Company anticipates that the annual contribution to the Retirement Plan in 2016 will be in the range of $5.0 million to $10.0 million. The Company expects that all subsidiaries having employees covered by the Retirement Plan will make contributions to the Retirement Plan. The funding of such contributions will come from amounts collected in rates in the Utility and Pipeline and Storage segments or through short-term borrowings or cash from operations.
The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The Company has established VEBA trusts and 401(h) accounts for its other post-retirement benefits. The Company has been making contributions to its VEBA trusts and 401(h) accounts over the last several years and anticipates that it will continue making contributions to the VEBA trusts and 401(h) accounts. During 2015, the Company contributed $2.0 million to its VEBA trusts and 401(h) accounts. The Company anticipates that the annual contribution to its VEBA trusts and 401(h) accounts in 2016 will be in the range of $2.0 million to $5.0 million. The funding of such contributions will come from amounts collected in rates in the Utility and Pipeline and Storage segments.
MARKET RISK SENSITIVE INSTRUMENTS
Energy Commodity Price Risk
The Company uses various derivative financial instruments (derivatives), including price swap agreements and futures contracts, as part of the Company’s overall energy commodity price risk management strategy in its Exploration and Production and Energy Marketing segments. Under this strategy, the Company manages a portion of the market risk associated with fluctuations in the price of natural gas and crude oil, thereby attempting to provide more stability to operating results. The Company has operating procedures in place that are administered by experienced management to monitor compliance with the Company’s risk management policies. The derivatives are not held for trading purposes. The fair value of these derivatives, as shown below, represents the amount that the Company would receive from, or pay to, the respective counterparties at September 30, 2015 to terminate the derivatives. However, the tables below and the fair value that is disclosed do not consider the physical side of the natural gas and crude oil transactions that are related to the financial instruments.
On July 21, 2010, the Dodd-Frank Act was signed into law. The Dodd-Frank Act includes provisions related to the swaps and over-the-counter derivatives markets. Certain provisions of the Dodd-Frank Act related to derivatives became effective July 16, 2011, but other provisions related to derivatives have or will become effective as federal agencies (including the CFTC, various banking regulators and the SEC) adopt rules to implement the law. Among other things, the Dodd-Frank Act (1) regulates certain participants in the swaps markets, including new entities defined as “swap dealers” and “major swap participants,” (2) requires clearing and exchange-trading of certain swaps that the CFTC determines must be cleared, (3) requires reporting and recordkeeping of swaps, and (4) enhances the CFTC’s enforcement authority, including the authority to establish position limits on derivatives and increases penalties for violations of the Commodity Exchange Act. For purposes of the Dodd-Frank Act, under rules adopted by the SEC and/or CFTC, the Company believes that it qualifies as a non-financial end user of derivatives, that is, as a non-financial entity that uses derivatives to hedge or mitigate commercial risk. Nevertheless, other rules that are being developed could have a significant impact on the Company. For example, the CFTC has imposed numerous registration, swaps documentation, business conduct, reporting, and recordkeeping requirements on swap dealers and major swap participants, which frequently are counterparties to the Company’s derivative hedging transactions. Regardless of the final capital and margin rules, concern remains that swap dealers and major swap participants will pass along their increased costs stemming from the final and proposed rules through higher transaction costs and prices or other direct or indirect costs. In addition, while the Company expects to be exempt from the Dodd-Frank Act’s requirement that certain swaps be cleared and traded on exchanges or swap execution facilities, the cost of entering into a non-exchange cleared swap that is available as an exchange cleared swap may be greater. The Dodd-Frank Act may also increase costs for derivative
recordkeeping, reporting, documentation, position limit compliance, and other compliance; cause parties to materially alter the terms of derivative contracts; cause parties to restructure certain derivative contracts; reduce the availability of derivatives to protect against risks that the Company encounters or to optimize assets; reduce the Company’s ability to monetize or restructure existing derivative contracts; and increase the Company’s exposure to less creditworthy counterparties, all of which could increase the Company’s business costs. The Company continues to monitor these developments but cannot predict the impact the Dodd-Frank Act may ultimately have on its operations.
In accordance with the authoritative guidance for fair value measurements, the Company has identified certain inputs used to recognize fair value as Level 3 (unobservable inputs). The Level 3 derivative net assets relate to crude oil swap agreements used to hedge forecasted sales at a specific location (southern California). The Company’s internal model that is used to calculate fair value applies a historical basis differential (between the sales locations and NYMEX) to a forward NYMEX curve because there is not a forward curve specific to this sales location. The Company does not believe that the fair value recorded would be significantly different from what it expects to receive upon settlement.
The Company uses the crude oil swaps classified as Level 3 to hedge against the risk of declining commodity prices and not as speculative investments. Gains or losses related to these Level 3 derivative net assets (including any reduction for credit risk) are deferred until the hedged commodity transaction occurs in accordance with the provisions of the existing guidance for derivative instruments and hedging activities. The Level 3 derivative net assets amount to $1.8 million at September 30, 2015 and represent 0.4% of the Total Net Assets shown in Item 8 at Note F - Fair Value Measurements at September 30, 2015.
The increase in the net fair value asset of the Level 3 positions from October 1, 2014 to September 30, 2015, as shown in Item 8 at Note F, was attributable to a decrease in the commodity price of crude oil (at the aforementioned sales location) relative to the swap prices during that period. The Company believes that these fair values reasonably represent the amounts that the Company would realize upon settlement based on commodity prices that were present at September 30, 2015.
The accounting rules for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At September 30, 2015, the Company determined that nonperformance risk would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.
The following tables disclose natural gas and crude oil price swap information by expected maturity dates for agreements in which the Company receives a fixed price in exchange for paying a variable price as quoted in various national natural gas publications or on the NYMEX. Notional amounts (quantities) are used to calculate the contractual payments to be exchanged under the contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2015. At September 30, 2015, the Company had not entered into any natural gas or crude oil price swap agreements extending beyond 2020.
Natural Gas Price Swap Agreements
Of the total Bcf above, 2.2 Bcf is accounted for as fair value hedges at a weighted average fixed rate of $3.81 per Mcf. The remaining 174.9 Bcf are accounted for as cash flow hedges at a weighted average fixed rate of $4.05 per Mcf.
Crude Oil Price Swap Agreements
At September 30, 2015, the Company would have received from its respective counterparties an aggregate of approximately $202.3 million to terminate the natural gas price swap agreements outstanding at that date. The Company would have received from its respective counterparties an aggregate of approximately $69.8 million to terminate the crude oil price swap agreements outstanding at September 30, 2015.
At September 30, 2014, the Company had natural gas price swap agreements covering 205.7 Bcf at a weighted average fixed rate of $4.33 per Mcf. The Company also had crude oil price swap agreements covering 3,285,000 Bbls at a weighted average fixed rate of $93.93 per Bbl.
The following table discloses the net contract volume purchased (sold), weighted average contract prices and weighted average settlement prices by expected maturity date for futures contracts used to manage natural gas price risk. At September 30, 2015, the Company did not hold any futures contracts with maturity dates extending beyond 2019 (the futures contracts maturing in 2019 were insignificant).
Futures Contracts
At September 30, 2015, the Company had long (purchased) contracts covering 17.8 Bcf of gas extending through 2018 at a weighted average contract price of $3.81 per Mcf and a weighted average settlement price of $2.95 per Mcf. Of this amount, 15.6 Bcf is accounted for as fair value hedges and are used by the Company’s Energy Marketing segment to hedge against rising prices, a risk to which this segment is exposed due to the fixed price gas sales commitments that it enters into with certain residential, commercial, industrial, public authority and wholesale customers. The remaining 2.2 Bcf is accounted for as cash flow hedges used to hedge against rising prices related to anticipated gas purchases for potential injections into storage. The Company would have paid $15.3 million to terminate these contracts at September 30, 2015.
At September 30, 2015, the Company had short (sold) contracts covering 6.4 Bcf of gas extending through 2018 at a weighted average contract price of $4.03 per Mcf and a weighted average settlement price of $3.04 per Mcf. Of this amount, 6.3 Bcf is accounted for as cash flow hedges as these contracts relate to the anticipated sale of natural gas by the Company's Energy Marketing segment. The remaining 0.1 Bcf is accounted for as fair value hedges, the majority of which are used to hedge against falling prices, a risk to which the Energy Marketing segment is exposed due to the fixed price gas purchase commitments that it enters into with certain natural gas suppliers. The Company would have received $6.4 million to terminate these contracts at September 30, 2015.
At September 30, 2014, the Company had long (purchased) contracts covering 18.1 Bcf of gas extending through 2018 at a weighted average contract price of $4.30 per Mcf and a weighted average settlement price of $4.23 per Mcf.
At September 30, 2014, the Company had short (sold) contracts covering 7.7 Bcf of gas extending through 2018 at a weighted average contract price of $4.64 per Mcf and a weighted average settlement price of $4.46 per Mcf.
Foreign Exchange Risk
The Company uses foreign exchange forward contracts to manage the risk of currency fluctuations associated with transportation costs denominated in Canadian currency in the Exploration and Production segment. All of these transactions are forecasted.
The following table discloses foreign exchange contract information by expected maturity dates. The Company receives a fixed price in exchange for paying a variable price as noted in the Canadian to U.S. dollar forward exchange rates. Notional amounts (Canadian dollars) are used to calculate the contractual payments to be exchanged under contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2015. At September 30, 2015, the Company had not entered into any foreign currency exchange contracts extending beyond 2020.
At September 20, 2015, absent other positions with the same counterparties, the Company would have paid its respective counterparties an aggregate of $3.0 million to terminate foreign exchange contracts.
Refer to Item 8 at Note G - Financial Instruments for a discussion of the Company’s exposure to credit risk related to its derivative financial instruments.
Interest Rate Risk
The fair value of long-term fixed rate debt is $2.1 billion at September 30, 2015. This fair value amount is not intended to reflect principal amounts that the Company will ultimately be required to pay. The following table presents the principal cash repayments and related weighted average interest rates by expected maturity date for the Company’s long-term fixed rate debt:
RATE AND REGULATORY MATTERS
Utility Operation
Delivery rates for both the New York and Pennsylvania divisions are regulated by the states’ respective public utility commissions and typically are changed only when approved through a procedure known as a “rate case.” Although neither division has a rate case on file, see below for a description of other rate proceedings affecting the New York division. In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs.
Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected primarily through a separately-stated “supply charge” on the customer bill.
New York Jurisdiction
Customer delivery rates charged by Distribution Corporation’s New York division were established in a rate order issued on December 21, 2007 by the NYPSC. In connection with an efficiency and conservation program, the rate order approved a revenue decoupling mechanism. The revenue decoupling mechanism “decouples” revenues from throughput by enabling the Company to collect from small volume customers its allowed margin on average weather normalized usage per customer. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation.
Following negotiations and other proceedings, on December 6, 2013, Distribution Corporation filed an agreement, also executed by the Department of Public Service and intervenors, extending existing rates through, at a minimum, September 30, 2015. Although customer rates were not changed, the parties agreed that the allowed rate of return on equity would be set, for ratemaking purposes, at 9.1%. Following conventional practice in New York, the agreement authorizes an “earnings sharing mechanism” (“ESM”). The ESM distributes earnings above the allowed rate of return as follows: from 9.5% to 10.5%, 50% would be allocated to shareholders, and 50% will be deferred for the benefit of customers; above 10.5%, 20% to shareholders and 80% will be deferred for the benefit of customers. The agreement further authorizes, and rates reflect, an increase in Distribution Corporation’s pipeline replacement spending by $8.2 million per year of the agreement. The agreement contains other terms and conditions of service that are customary for settlement agreements recently approved by the NYPSC. A $7.5 million ($4.9 million after-tax) refund provision was passed back to ratepayers during 2014 after the NYPSC approved the settlement agreement without modification in an order issued on May 8, 2014. All significant terms of the agreement, including existing rates, continue in effect beyond September 30, 2015 until modified by the NYPSC. The agreement also states that nothing in the agreement precludes the parties from meeting to discuss extending the agreement on mutually acceptable terms, and presenting such extension to the NYPSC for approval. On May 22, 2015, Distribution Corporation filed with the NYPSC a Notice of Impending Settlement Discussions stating that settlement discussions would be scheduled in the near future, and that such discussions might include, among other things, the possible extension of the agreement on mutually acceptable terms. Distribution Corporation is currently involved in such settlement discussions.
Pennsylvania Jurisdiction
Distribution Corporation’s current delivery charges in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007.
Pipeline and Storage
On September 29, 2015, Supply Corporation filed a rate case settlement at the FERC that would, upon approval, extend the Company’s current FERC-approved rate case settlement with a required rate case filing at the latest by December 31, 2019 and prohibit any party from seeking to initiate a rate case proceeding before September 30, 2017. Prior to this settlement, Supply Corporation had been otherwise required by its current rate settlement to make a general rate filing no later than January 1, 2016. The settlement extension provides for, among other things, the following: Supply Corporation will reduce its maximum reservation, capacity, demand and deliverability rates by 2% on November 1, 2015 and by an additional 2% on November 1, 2016. Supply Corporation will also adopt a mechanism that allows it to recover, as a surcharge, certain pipeline safety and greenhouse gas costs it may incur as a result of new rules and regulations. FERC approved the settlement extension on November 13, 2015.
Empire does not have a rate case currently on file with the FERC, and is not subject to any requirement to make a future general rate filing. Empire is also not barred from filing a general rate case at any time.
ENVIRONMENTAL MATTERS
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory requirements.
For further discussion of the Company's environmental exposures, refer to Item 8 at Note I - Commitments and Contingencies under the heading “Environmental Matters.”
Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation. In the United States, these efforts include legislative proposals and EPA regulations at the federal level, actions at the state level, and private party litigation related to greenhouse gas emissions. While the U.S. Congress has from time to time considered legislation aimed at reducing emissions of greenhouse gases, Congress has not yet passed any federal climate change legislation and we cannot predict when or if Congress will pass such legislation and in what form. In the absence of such legislation, the EPA is regulating greenhouse gas emissions pursuant to the authority granted to it by the federal Clean Air Act. For example, in April 2012, the EPA adopted rules which restrict emissions associated with oil and natural gas drilling. In 2015, the EPA proposed new rules regulating methane and volatile organic compound emissions from new or modified oil and gas emissions sources. If adopted as proposed, these new rules would impose more stringent leak detection and repair requirements, and would further address reporting and control of methane and volatile organic compound emissions. In addition, the U.S. Congress has from time to time considered bills that would establish a cap-and-trade program to reduce emissions of greenhouse gases. The Company currently complies with California cap-and-trade guidelines, which increases the Company's cost of environmental compliance in its Exploration and Production segment operations. Legislation or regulation that restricts carbon emissions could increase the Company’s cost of environmental compliance by requiring the Company to install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. International, federal, state or regional climate change and greenhouse gas measures could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities, or impose additional monitoring and reporting requirements. Climate change and greenhouse gas initiatives, and incentives to conserve energy or use alternative energy sources, could also reduce demand for oil and natural gas. But legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Company by increasing demand for natural gas, because substantially fewer carbon emissions per Btu of heat generated are associated with the use of natural gas than with certain alternate fuels such as coal and oil. The effect (material or not) on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.
NEW AUTHORITATIVE ACCOUNTING AND FINANCIAL REPORTING GUIDANCE
For discussion of the recently issued authoritative accounting and financial reporting guidance, refer to Item 8 at Note A - Summary of Significant Accounting Policies under the heading “New Authoritative Accounting and Financial Reporting Guidance.”
EFFECTS OF INFLATION
Although the rate of inflation has been relatively low over the past few years, the Company’s operations remain sensitive to increases in the rate of inflation because of its capital spending and the regulated nature of a significant portion of its business.
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
The Company is including the following cautionary statement in this Form 10-K to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent
forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:
1.
Factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations;
2.
Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves;
3.
Changes in the price of natural gas or oil;
4.
Financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions;
5.
Changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing;
6.
Governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal;
7.
Changes in price differential between similar quantities of natural gas or oil at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations;
8.
Other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date;
9.
The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company;
10.
Uncertainty of oil and gas reserve estimates;
11.
Significant differences between the Company’s projected and actual production levels for natural gas or oil;
12.
Delays or changes in costs or plans with respect to Company projects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators;
13.
Changes in demographic patterns and weather conditions;
14.
Changes in the availability, price or accounting treatment of derivative financial instruments;
15.
Changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services;
16.
The creditworthiness or performance of the Company’s key suppliers, customers and counterparties;
17.
Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation;
18.
Significant differences between the Company’s projected and actual capital expenditures and operating expenses;
19.
Changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities;
20.
Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or
21.
Increasing costs of insurance, changes in coverage and the ability to obtain insurance.
The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
Item 7A
Item 7A
Quantitative and Qualitative Disclosures About Market Risk
Refer to the “Market Risk Sensitive Instruments” section in Item 7, MD&A.
Item 8
Item 8
Financial Statements and Supplementary Data
All other schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes thereto.
Supplementary Data
Supplementary data that is included in Note K - Quarterly Financial Data (unaudited) and Note M - Supplementary Information for Oil and Gas Producing Activities (unaudited), appears under this Item, and reference is made thereto.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of National Fuel Gas Company:
In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the financial position of National Fuel Gas Company and its subsidiaries at September 30, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2015, based on criteria established in Internal Control - Integrated Framework 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PRICEWATERHOUSECOOPERS LLP
Buffalo, New York
November 20, 2015
NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND EARNINGS
REINVESTED IN THE BUSINESS
See Notes to Consolidated Financial Statements
NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
See Notes to Consolidated Financial Statements
NATIONAL FUEL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements
NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
See Notes to Consolidated Financial Statements
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note A - Summary of Significant Accounting Policies
Principles of Consolidation
The Company consolidates all entities in which it has a controlling financial interest. All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting.
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Reclassification
Due to the adoption of the authoritative guidance regarding the presentation of debt issuance costs, certain prior year amounts have been reclassified to conform with current year presentation. The Company reclassified debt issuance costs related to long-term debt previously shown as Unamortized Debt Expense as a direct deduction from the carrying value of Long-Term Debt on the Consolidated Balance Sheet.
Regulation
The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which conform to GAAP, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Reference is made to Note C - Regulatory Matters for further discussion.
Revenue Recognition
The Company’s Exploration and Production segment records revenue based on entitlement, which means that revenue is recorded based on the actual amount of gas or oil that is delivered to a pipeline and the Company’s ownership interest in the producing well. If a production imbalance occurs between what was supposed to be delivered to a pipeline and what was actually produced and delivered, the Company accrues the difference as an imbalance.
The Company’s Pipeline and Storage segment records revenue for natural gas transportation and storage services. Revenue from reservation charges on firm contracted capacity is recognized through equal monthly charges over the contract period regardless of the amount of gas that is transported or stored. Commodity charges on firm contracted capacity and interruptible contracts are recognized as revenue when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage field. The point of delivery into the pipeline or injection or withdrawal from storage is the point at which ownership and risk of loss transfers to the buyer of such transportation and storage services.
In the Company’s Gathering segment, revenue is recorded at the point at which gathered volumes are delivered into interstate pipelines.
The Company’s Utility segment records revenue for gas sales and transportation in the period that gas is delivered to customers. This includes the recording of receivables for gas delivered but not yet billed to customers based on the Company's estimate of the amount of gas delivered between the last meter reading date and the end of the accounting period. Such receivables are a component of Unbilled Revenue on the Consolidated Balance Sheets.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Company’s Energy Marketing segment records revenue for gas sales in the period that gas is delivered to customers. This includes the recording of receivables for gas delivered but not yet billed to customers based on the Company's estimate of the amount of gas delivered between the last meter reading date and the end of the accounting period. Such receivables are a component of Unbilled Revenue on the Consolidated Balance Sheets.
Allowance for Uncollectible Accounts
The allowance for uncollectible accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance is determined based on historical experience, the age and other specific information about customer accounts. Account balances are charged off against the allowance twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered.
Regulatory Mechanisms
The Company’s rate schedules in the Utility segment contain clauses that permit adjustment of revenues to reflect price changes from the cost of purchased gas included in base rates. Differences between amounts currently recoverable and actual adjustment clause revenues, as well as other price changes and pipeline and storage company refunds not yet includable in adjustment clause rates, are deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers. Such amounts are generally recovered from (or passed back to) customers during the following fiscal year.
Estimated refund liabilities to ratepayers represent management’s current estimate of such refunds. Reference is made to Note C - Regulatory Matters for further discussion.
The impact of weather on revenues in the Utility segment’s New York rate jurisdiction is tempered by a WNC, which covers the eight-month period from October through May. The WNC is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather. Weather that is warmer than normal results in a surcharge being added to customers’ current bills, while weather that is colder than normal results in a refund being credited to customers’ current bills. Since the Utility segment’s Pennsylvania rate jurisdiction does not have a WNC, weather variations have a direct impact on the Pennsylvania rate jurisdiction’s revenues.
The impact of weather normalized usage per customer account in the Utility segment’s New York rate jurisdiction is tempered by a revenue decoupling mechanism. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation. Weather normalized usage per account that exceeds the average weather normalized usage per customer account results in a refund being credited to customers’ bills. Weather normalized usage per account that is below the average weather normalized usage per account results in a surcharge being added to customers’ bills. The surcharge or credit is calculated over a twelve-month period ending December 31st, and applied to customer bills annually, beginning March 1st.
In the Pipeline and Storage segment, the allowed rates that Supply Corporation and Empire bill their customers are based on a straight fixed-variable rate design, which allows recovery of all fixed costs, including return on equity and income taxes, through fixed monthly reservation charges. Because of this rate design, changes in throughput due to weather variations do not have a significant impact on the revenues of Supply Corporation or Empire.
Property, Plant and Equipment
In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. For further discussion of capitalized costs, refer to Note M - Supplementary Information for Oil and Gas Producing Activities.
Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The natural gas and oil prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. The book value of the oil and gas properties exceeded the ceiling at September 30, 2015 as well as at June 30, 2015 and March 31, 2015. As such, the Company recognized pre-tax impairment charges of $1.1 billion for the year ended September 30, 2015. Deferred income tax benefits of $476.1 million related to the impairment charges were also recognized for the year ended September 30, 2015. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2015, 2014, and 2013, estimated future net cash flows were increased by $194.5 million, decreased by $33.6 million and increased by $71.6 million, respectively.
The principal assets of the Utility and Pipeline and Storage segments, consisting primarily of gas plant in service, are recorded at the historical cost when originally devoted to service.
Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense. The original cost of the regulated subsidiaries’ property, plant and equipment retired, and the cost of removal less salvage, are charged to accumulated depreciation.
Depreciation, Depletion and Amortization
For oil and gas properties, depreciation, depletion and amortization is computed based on quantities produced in relation to proved reserves using the units of production method. The cost of unproved oil and gas properties is excluded from this computation. In the All Other category, for timber properties, depletion, determined on a property by property basis, is charged to operations based on the actual amount of timber cut in relation to the total amount of recoverable timber. For all other property, plant and equipment, depreciation and amortization is computed using the straight-line method in amounts sufficient to recover costs over the estimated service lives of property in service. The following is a summary of depreciable plant by segment:
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Average depreciation, depletion and amortization rates are as follows:
(1)
Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note M - Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $1.49, $1.82 and $1.98 per Mcfe of production in 2015, 2014 and 2013, respectively.
Goodwill
The Company has recognized goodwill of $5.5 million as of September 30, 2015 and 2014 on its Consolidated Balance Sheets related to the Company’s acquisition of Empire in 2003. The Company accounts for goodwill in accordance with the current authoritative guidance, which requires the Company to test goodwill for impairment annually. At September 30, 2015, 2014 and 2013, the fair value of Empire was greater than its book value. As such, the goodwill was not considered impaired at those dates. Going back to the origination of the goodwill in 2003, the Company has never recorded an impairment of its goodwill balance.
Financial Instruments
Unrealized gains or losses from the Company’s investments in an equity mutual fund and the stock of an insurance company (securities available for sale) are recorded as a component of accumulated other comprehensive income (loss). Reference is made to Note G - Financial Instruments for further discussion.
The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil and to manage a portion of the risk of currency fluctuations associated with transportation costs denominated in Canadian currency. These instruments include price swap agreements and futures contracts. The Company accounts for these instruments as either cash flow hedges or fair value hedges. In both cases, the fair value of the instrument is recognized on the Consolidated Balance Sheets as either an asset or a liability labeled Fair Value of Derivative Financial Instruments. Reference is made to Note F - Fair Value Measurements for further discussion concerning the fair value of derivative financial instruments.
For effective cash flow hedges, the offset to the asset or liability that is recorded is a gain or loss recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets. The gain or loss recorded in accumulated other comprehensive income (loss) remains there until the hedged transaction occurs, at which point the gains or losses are reclassified to operating revenues, purchased gas expense or operation and maintenance expense on the Consolidated Statements of Income. Reference is made to Note G - Financial Instruments for further discussion concerning cash flow hedges.
For fair value hedges, the offset to the asset or liability that is recorded is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income. However, in the case of fair value hedges, the Company also records an asset or liability on the Consolidated Balance Sheets representing the change in fair value of the asset or firm commitment that is being hedged (see Other Current Assets section in this footnote). The offset to this asset or liability is a gain or loss recorded to operating revenues or purchased gas expense on the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Consolidated Statements of Income as well. If the fair value hedge is effective, the gain or loss from the derivative financial instrument is offset by the gain or loss that arises from the change in fair value of the asset or firm commitment that is being hedged. Reference is made to Note G - Financial Instruments for further discussion concerning fair value hedges.
Accumulated Other Comprehensive Income (Loss)
The components of Accumulated Other Comprehensive Income (Loss) and changes for the year ended September 30, 2015, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands):
The amounts included in accumulated other comprehensive income (loss) related to the funded status of the Company’s pension and other post-retirement benefit plans consist of prior service costs and accumulated losses. The total amount for prior service (cost) credit was ($1.5 million) and $0.2 million at September 30, 2015 and 2014, respectively. The total amount for accumulated losses was $68.3 million and $56.2 million at September 30, 2015 and 2014, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Reclassifications Out of Accumulated Other Comprehensive Income (Loss)
The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the year ended September 30, 2015 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):
(1)
These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note H - Retirement Plan and Other Post-Retirement Benefits for additional details.
Gas Stored Underground - Current
In the Utility segment, gas stored underground - current in the amount of $26.8 million is carried at lower of cost or market, on a LIFO method. Based upon the average price of spot market gas purchased in September 2015, including transportation costs, the current cost of replacing this inventory of gas stored underground - current exceeded the amount stated on a LIFO basis by approximately $13.8 million at September 30, 2015. All other gas stored underground - current, which is in the Energy Marketing segment, is carried at an average cost method, subject to lower of cost or market adjustments.
Unamortized Debt Expense
Costs associated with the reacquisition of debt related to rate-regulated subsidiaries are deferred and amortized over the remaining life of the issue or the life of the replacement debt in order to match regulatory treatment. At September 30, 2015, the remaining weighted average amortization period for such costs was approximately 4 years.
Income Taxes
The Company and its subsidiaries file a consolidated federal income tax return. State tax returns are filed on a combined or separate basis depending on the applicable laws in the jurisdictions where tax returns are filed.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Investment tax credit, prior to its repeal in 1986, was deferred and is being amortized over the estimated useful lives of the related property, as required by regulatory authorities having jurisdiction.
The Company reports a liability or a reduction of deferred tax assets for unrecognized tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return. When applicable, the Company recognizes interest relating to uncertain tax positions in Other Interest Expense and penalties in Other Income.
Consolidated Statement of Cash Flows
For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents.
Hedging Collateral Deposits
This is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions. In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instrument liability or asset balances.
Other Current Assets
The components of the Company’s Other Current Assets are as follows:
Other Accruals and Current Liabilities
The components of the Company’s Other Accruals and Current Liabilities are as follows:
Customer Advances
The Company’s Utility and Energy Marketing segments have balanced billing programs whereby customers pay their estimated annual usage in equal installments over a twelve-month period. Monthly payments under the balanced billing programs are typically higher than current month usage during the summer months. During the winter months, monthly payments under the balanced billing programs are typically lower than current month
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
usage. At September 30, 2015 and 2014, customers in the balanced billing programs had advanced excess funds of $16.2 million and $19.0 million, respectively.
Customer Security Deposits
The Company, in its Utility, Pipeline and Storage, and Energy Marketing segments, often times requires security deposits from marketers, producers, pipeline companies, and commercial and industrial customers before providing services to such customers. At September 30, 2015 and 2014, the Company had received customer security deposits amounting to $16.5 million and $15.8 million, respectively.
Earnings Per Common Share
Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the only potentially dilutive securities the Company has outstanding are stock options, SARs, restricted stock units and performance shares. As the Company recognized a net loss in 2015, the aforementioned securities, amounting to 709,063 securities, were not recognized in the diluted earnings per share calculation for 2015. For 2014 and 2013, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. Stock options, SARs, restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. For 2014 and 2013, 1,007 securities and 181,418 securities were excluded as being antidilutive, respectively.
Stock-Based Compensation
The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, SARs, restricted stock, restricted stock units, performance units or performance shares. The Company follows authoritative guidance which requires the measurement and recognition of compensation cost at fair value for all share-based payments. Stock options and SARs under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no stock option or SAR is exercisable less than one year or more than ten years after the date of each grant. The Company has chosen the Black-Scholes-Merton closed form model to calculate the compensation expense associated with stock options and SARs.
Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. The market value of restricted stock on the date of the award is recorded as compensation expense over the vesting period. Certificates for shares of restricted stock awarded under the Company’s stock option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective. Restrictions on restricted stock awards generally lapse ratably over a period of not more than ten years after the date of each grant. Restricted stock units also are subject to restrictions on vesting and transferability. Restricted stock units, both performance and non-performance based, represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. The performance based and non-performance based restricted stock units do not entitle the participants to dividend and voting rights. The accounting for performance based and non-performance based restricted stock units is the same as the accounting for restricted share awards, except that the fair value at the date of grant of the restricted stock units (represented by the market value of Company common stock on the date of the award) must be reduced by the present value of forgone dividends over the vesting term of the award. The fair value of restricted stock units on the date of award is recorded as compensation expense over the vesting period.
Performance shares are an award constituting units denominated in common stock of the Company, the number of which may be adjusted over a performance cycle based upon the extent to which performance goals
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
have been satisfied. Earned performance shares may be distributed in the form of shares of common stock of the Company, an equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company. The performance shares do not entitle the participant to receive dividends during the vesting period. For performance shares based on a return on capital goal, the fair value at the date of grant of the performance shares is determined by multiplying the expected number of performance shares to be issued by the market value of Company common stock on the date of grant reduced by the present value of forgone dividends. For performance shares based on a total shareholder return goal, the Company uses the Monte Carlo simulation technique to estimate the fair value price at the date of grant.
Refer to Note E - Capitalization and Short-Term Borrowings under the heading “Stock Option and Stock Award Plans” for additional disclosures related to stock-based compensation awards for all plans.
New Authoritative Accounting and Financial Reporting Guidance
In May 2014, the FASB issued authoritative guidance regarding revenue recognition. The authoritative guidance provides a single, comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The original effective date of this authoritative guidance was as of the Company's first quarter of fiscal 2018. However, the FASB has delayed the effective date of the new revenue standard by one year, and the guidance will now be effective as of the Company's first quarter of fiscal 2019. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements and disclosures.
In June 2014, the FASB issued authoritative guidance regarding accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the employee has completed the requisite service period. This authoritative guidance requires that such performance targets that affect vesting be treated as performance conditions, meaning that the performance target should not be factored in the calculation of the award at the grant date. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2017, with early adoption permitted. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.
In April 2015, the FASB issued authoritative guidance regarding the presentation of debt issuance costs. The authoritative guidance requires that all costs incurred to issue debt be presented in the balance sheet as a direct deduction from the carrying value of the debt. The Company early adopted this guidance at September 30, 2015 on a retrospective basis.
In July 2015, the FASB issued authoritative guidance simplifying inventory measurement by requiring companies to value inventory at the lower of cost and net realizable value. The authoritative guidance applies to all inventory other than inventory that is measured using last-in, first-out or the retail inventory method. The intention of this authoritative guidance is to eliminate some diversity in practice. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2018, with early adoption permitted. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.
Note B - Asset Retirement Obligations
The Company accounts for asset retirement obligations in accordance with the authoritative guidance that requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. An asset retirement obligation is defined as a legal obligation associated with the retirement of a tangible long-lived asset in which the timing and/or method of settlement may or may not be conditional on a future event that may or may not be within the control of the Company. When the liability is initially recorded, the entity capitalizes the estimated cost of retiring the asset as part of the carrying amount of the related long-lived asset. Over time, the liability is adjusted to its present value each period and the capitalized cost is depreciated over the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
useful life of the related asset. The Company estimates the fair value of its asset retirement obligations based on the discounting of expected cash flows using various estimates, assumptions and judgments regarding certain factors such as the existence of a legal obligation for an asset retirement obligation; estimated amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. Asset retirement obligations incurred in the current period were Level 3 fair value measurements as the inputs used to measure the fair value are unobservable.
The Company has recorded an asset retirement obligation representing plugging and abandonment costs associated with the Exploration and Production segment’s crude oil and natural gas wells and has capitalized such costs in property, plant and equipment (i.e. the full cost pool).
In addition to the asset retirement obligation recorded in the Exploration and Production segment, the Company has recorded future asset retirement obligations associated with the plugging and abandonment of natural gas storage wells in the Pipeline and Storage segment and the removal of asbestos and asbestos-containing material in various facilities in the Utility and Pipeline and Storage segments. The Company has also recorded asset retirement obligations for certain costs connected with the retirement of the distribution mains and services components of the pipeline system in the Utility segment, with the transmission mains and other components in the pipeline system in the Pipeline and Storage segment and with gathering lines and other components in the Gathering segment. These retirement costs within the distribution, transmission and gathering systems are primarily for the capping and purging of pipe, which are generally abandoned in place when retired, as well as for the clean-up of PCB contamination associated with the removal of certain pipe.
A reconciliation of the Company’s asset retirement obligations are shown below:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note C - Regulatory Matters
Regulatory Assets and Liabilities
The Company has recorded the following regulatory assets and liabilities:
(1)
The Company recovers the cost of its regulatory assets but generally does not earn a return on them. There are a few exceptions to this rule. For example, the Company does earn a return on Unrecovered Purchased Gas Costs and, in the New York jurisdiction of its Utility segment, earns a return, within certain parameters, on the excess of cumulative funding to the pension plan over the cumulative amount collected in rates.
(2)
Included in Other Regulatory Assets on the Consolidated Balance Sheets.
(3)
Amounts are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2015 and September 30, 2014 since such amounts are expected to be recovered from ratepayers in the next 12 months.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(4)
$6,522 and $9,989 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2015 and 2014, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $4,373 and $4,853 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2015 and 2014, respectively.
(5)
The September 30, 2015 amount is included in Other Regulatory Liabilities on the Consolidated Balance Sheet at September 30, 2015. The September 30, 2014 amount is included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet at September 30, 2014 since such amount is expected to be passed back to ratepayers in the next 12 months.
(6)
$5,346 and $5,267 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2015 and 2014, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $27,577 and $27,502 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2015 and 2014, respectively.
If for any reason the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Balance Sheets and included in income of the period in which the discontinuance of regulatory accounting treatment occurs.
Cost of Removal Regulatory Liability
In the Company’s Utility and Pipeline and Storage segments, costs of removing assets (i.e. asset retirement costs) are collected from customers through depreciation expense. These amounts are not a legal retirement obligation as discussed in Note B - Asset Retirement Obligations. Rather, they are classified as a regulatory liability in recognition of the fact that the Company has collected dollars from the customer that will be used in the future to fund asset retirement costs.
NYPSC Assessment
On April 7, 2009, the Governor of the State of New York signed into law an amendment to the Public Service Law increasing the allowed utility assessment from the then current rate of one-third of one percent to one percent of a utility’s in-state gross operating revenue, together with a temporary surcharge (expiring March 31, 2014) equal, as applied, to an additional one percent of the utility’s in-state gross operating revenue. Pursuant to a New York State budget agreement in 2014, the temporary increase in the assessment will be phased out over a three year period ending July 1, 2017. The NYPSC, in a generic proceeding initiated for the purpose of implementing the amended law, has authorized the recovery, through rates, of the full cost of the increased assessment. The assessment is currently being applied to customer bills in the Utility segment’s New York jurisdiction.
NYPSC Rate Proceeding
Following negotiations and other proceedings, on December 6, 2013, Distribution Corporation filed an agreement, also executed by the Department of Public Service and intervenors, extending existing rates through, at a minimum, September 30, 2015. Although customer rates were not changed, the parties agreed that the allowed rate of return on equity would be set, for ratemaking purposes, at 9.1%. Following conventional practice in New York, the agreement authorizes an “earnings sharing mechanism” (“ESM”). The ESM distributes earnings above the allowed rate of return as follows: from 9.5% to 10.5%, 50% would be allocated to shareholders, and 50% will be deferred for the benefit of customers; above 10.5%, 20% would be allocated to shareholders and 80% will be deferred for the benefit of customers. The agreement further authorizes, and rates reflect, an increase in Distribution Corporation’s pipeline replacement spending by $8.2 million per year of the agreement. The agreement contains other terms and conditions of service that are customary for settlement agreements recently approved by the NYPSC. A $7.5 million refund provision was passed back to ratepayers during 2014 after the NYPSC approved the settlement
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
agreement without modification in an order issued on May 8, 2014. All significant terms of the agreement, including existing rates, continue in effect beyond September 30, 2015 until modified by the NYPSC. The agreement also states that nothing in the agreement precludes the parties from meeting to discuss extending the agreement on mutually acceptable terms, and presenting such extension to the NYPSC for approval. On May 22, 2015, Distribution Corporation filed with the NYPSC a Notice of Impending Settlement Discussions stating that settlement discussions would be scheduled in the near future, and that such discussions might include, among other things, the possible extension of the agreement on mutually acceptable terms. Distribution Corporation is currently involved in such settlement discussions.
FERC Rate Proceeding
On September 29, 2015, Supply Corporation filed a rate case settlement at the FERC that would, upon approval, extend the Company’s current FERC-approved rate case settlement with a required rate case filing at the latest by December 31, 2019 and prohibit any party from seeking to initiate a rate case proceeding before September 30, 2017. Prior to this settlement, Supply Corporation had been otherwise required by its current rate settlement to make a general rate filing no later than January 1, 2016. The settlement extension provides for, among other things, the following: Supply Corporation will reduce its maximum reservation, capacity, demand and deliverability rates by 2% on November 1, 2015 and by an additional 2% on November 1, 2016. Supply Corporation will also adopt a mechanism that allows it to recover, as a surcharge, certain pipeline safety and greenhouse gas costs it may incur as a result of new rules and regulations. FERC approved the settlement extension on November 13, 2015.
Off-System Sales and Capacity Release Credits
The Company, in its Utility segment, has entered into off-system sales and capacity release transactions. Most of the margins on such transactions are returned to the customer with only a small percentage being retained by the Company. The amount owed to the customer has been deferred as a regulatory liability.
Note D - Income Taxes
The components of federal and state income taxes included in the Consolidated Statements of Income are as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income (loss) before income taxes. The following is a reconciliation of this difference:
Significant components of the Company’s deferred tax liabilities and assets were as follows:
As a result of certain realization requirements of the authoritative guidance on stock-based compensation, the table of deferred tax liabilities and assets shown above does not include certain deferred tax assets that arose directly from excess tax deductions related to stock-based compensation. Tax benefits of $9.1 million, $4.6 million and $0.7 million relating to the excess stock-based compensation deductions were recorded in Paid in Capital during the years ended September 30, 2015, September 30, 2014 and September 30, 2013, respectively. Cumulative tax benefits of $32.8 million and $34.2 million remain as of September 30, 2015 and September 30, 2014, respectively, and will be recorded in Paid in Capital in future years when such tax benefits are realized.
Regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $89.4 million and $91.7 million at September 30, 2015 and 2014, respectively. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
prior ratemaking practices, amounted to $168.2 million and $163.5 million at September 30, 2015 and 2014, respectively. Included in the above are regulatory liabilities and assets relating to the tax accounting method change noted below. The amounts are as follows: regulatory liabilities of $52.6 million as of September 30, 2015 and 2014 and regulatory assets of $88.7 million and $85.3 million as of September 30, 2015 and 2014, respectively.
The following is a reconciliation of the change in unrecognized tax benefits:
As a result of certain examinations in progress (discussed below), the Company anticipates the balance of unrecognized tax benefits could be reduced during the next 12 months. As of September 30, 2015, the entire balance of unrecognized tax benefits would favorably impact the effective tax rate, if recognized.
The IRS is currently conducting examinations of the Company for fiscal 2015 and fiscal 2014 in accordance with the Compliance Assurance Process (“CAP”). The CAP audit employs a real time review of the Company’s books and tax records by the IRS that is intended to permit issue resolution prior to the filing of the tax return. The federal statute of limitations remains open for fiscal 2009 and later years. During fiscal 2009, consent was received from the IRS National Office approving the Company’s application to change its tax method of accounting for certain capitalized costs relating to its utility property. While local IRS examiners issued no-change reports for fiscal 2009 through 2013, the IRS has reserved the right to re-examine these years, pending the anticipated issuance of IRS guidance addressing the issue for natural gas utilities.
The Company is also subject to various routine state income tax examinations. The Company’s principal subsidiaries operate mainly in four states which have statutes of limitations that generally expire between three to four years from the date of filing of the income tax return.
As of September 30, 2015, the Company has a federal net operating loss (NOL) carryover of $343 million, which expires in varying amounts between 2023 and 2033, and a minimum tax credit carryforward of $54 million, that has no expiration date. Approximately $7.3 million of the NOL carryforward is subject to certain annual limitations, and $87 million is attributable to excess tax deductions related to stock-based compensation as discussed above. In addition, the Company has state NOL carryovers in Pennsylvania, California and New York of $333 million, $207 million and $96 million, respectively, which begin to expire in varying amounts between 2025 and 2035.
During fiscal 2014, legislation was enacted reducing the corporate tax rate in New York from 7.1% to 6.5%, effective for tax years beginning after January 1, 2016. As a result, a deferred tax benefit of approximately $2.8 million was recorded in the accompanying financial statements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note E - Capitalization and Short-Term Borrowings
Summary of Changes in Common Stock Equity
(1)
Paid in Capital includes tax benefits of $9.1 million, $4.6 million and $0.7 million for September 30, 2015, 2014 and 2013, respectively, related to stock-based compensation.
(2)
Paid in Capital includes compensation costs associated with stock option, SARs, performance share and/or restricted stock awards. The expense is included within Net Income Available For Common Stock, net of tax benefits.
(3)
The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt. At September 30, 2015, $959.0 million of accumulated earnings was free of such limitations.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Common Stock
The Company has various plans which allow shareholders, employees and others to purchase shares of the Company common stock. The National Fuel Gas Company Direct Stock Purchase and Dividend Reinvestment Plan allows shareholders to reinvest cash dividends and make cash investments in the Company’s common stock and provides investors the opportunity to acquire shares of the Company common stock without the payment of any brokerage commissions in connection with such acquisitions. The 401(k) Plans allow employees the opportunity to invest in the Company common stock, in addition to a variety of other investment alternatives. Generally, at the discretion of the Company, shares purchased under these plans are either original issue shares purchased directly from the Company or shares purchased on the open market by an independent agent. During 2015, the Company issued 124,214 original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan and 92,887 original issue shares of common stock for the Company's 401(k) plans.
During 2015, the Company issued 206,523 original issue shares of common stock as a result of stock option and SARs exercises and 48,490 original issue shares of common stock for restricted stock units that vested. Holders of stock options, SARs, restricted share awards or restricted stock units will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding taxes. During 2015, 50,467 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.
The Company also has a director stock program under which it issues shares of Company common stock to the non-employee directors of the Company who receive compensation under the Company’s 2009 Non-Employee Director Equity Compensation Plan, as partial consideration for the directors’ services during the fiscal year. Under this program, the Company issued 15,516 original issue shares of common stock during 2015.
Shareholder Rights Plan
In 1996, the Company’s Board of Directors adopted a shareholder rights plan (Plan). The Plan has been amended several times since it was adopted and is now embodied in an Amended and Restated Rights Agreement effective December 4, 2008, a copy of which was included as an exhibit to the Form 8-K filed by the Company on December 4, 2008.
Pursuant to the Plan, the holders of the Company’s common stock have one right (Right) for each of their shares. Each Right is initially evidenced by the Company’s common stock certificates representing the outstanding shares of common stock.
The Rights have anti-takeover effects because they will cause substantial dilution of the Company’s common stock if a person (an Acquiring Person) attempts to acquire the Company on terms not approved by the Board of Directors.
The Rights become exercisable upon the occurrence of a Distribution Date as described below, but after a Distribution Date, Rights that are owned by an Acquiring Person will be null and void. At any time following a Distribution Date, each holder of a Right may exercise its right to receive, upon payment of an amount calculated under the Rights Agreement, common stock of the Company (or, under certain circumstances, other securities or assets of the Company) having a value equal to two times the amount paid to exercise the Right. However, the Rights are subject to redemption or exchange by the Company prior to their exercise as described below.
A Distribution Date would occur upon the earlier of (i) ten days after the public announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of the Company’s common stock or other voting stock (including Synthetic Long Positions as defined in the Plan) having 10% or more of the total voting power of the Company’s common stock and other voting stock or (ii) ten days after the commencement or announcement by a person or group of an intention to make a tender or exchange offer that would result in that
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person acquiring, or obtaining the right to acquire, beneficial ownership of the Company’s common stock or other voting stock having 10% or more of the total voting power of the Company’s common stock and other voting stock.
In certain situations after a person or group has acquired beneficial ownership of 10% or more of the total voting power of the Company’s stock as described above, each holder of a Right will have the right to receive, upon exercise of the Right, common stock of the acquiring company having a value equal to two times the amount paid to exercise the Right. These situations would arise if the Company is acquired in a merger or other business combination or if 50% or more of the Company’s assets or earning power is sold or transferred.
At any time prior to the end of the business day on the tenth day following the Distribution Date, the Company may redeem the Rights in whole, but not in part, at a price of $0.005 per Right, payable in cash or stock. A decision to redeem the Rights requires the vote of 75% of the Company’s full Board of Directors. Also, at any time following the Distribution Date, 75% of the Company’s full Board of Directors may vote to exchange the Rights, in whole or in part, at an exchange rate of one share of common stock, or other property deemed to have the same value, per Right, subject to certain adjustments.
Upon exercise of the Rights, the Company may need additional regulatory approvals to satisfy the requirements of the Rights Agreement. The Rights will expire on July 31, 2018, unless earlier than that date, they are exchanged or redeemed or the Plan is amended to extend the expiration date.
Stock Option and Stock Award Plans
The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, SARs, restricted stock, restricted stock units, performance units or performance shares.
Stock-based compensation expense for the years ended September 30, 2015, 2014 and 2013 was approximately $2.1 million, $10.5 million, and $11.5 million, respectively. Stock-based compensation expense is included in operation and maintenance expense on the Consolidated Statements of Income. The total income tax benefit related to stock-based compensation expense during the years ended September 30, 2015, 2014 and 2013 was approximately $0.9 million, $4.3 million and $4.6 million, respectively. A portion of stock-based compensation expense is subject to capitalization under IRS uniform capitalization rules. Stock-based compensation of $0.1 million, $0.1 million and less than $0.1 million was capitalized under these rules during the years ended September 30, 2015, 2014 and 2013, respectively.
The Company realized excess tax benefits related to stock-based compensation of $7.7 million, $3.1 million, and $3.6 million for the fiscal years ended September 30, 2015, 2014 and 2013, respectively. These amounts are recorded in Paid in Capital when they meet the realization requirements of the authoritative guidance on stock-based compensation.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Stock Options
Transactions involving option shares for all plans are summarized as follows:
(1)
Includes shares available for SARs, restricted stock and performance share grants.
The total intrinsic value of stock options exercised during the years ended September 30, 2015, 2014 and 2013 totaled approximately $5.1 million, $13.7 million, and $11.6 million, respectively. For 2015, 2014 and 2013, the amount of cash received by the Company from the exercise of such stock options was approximately $5.6 million, $7.4 million, and $2.6 million, respectively. The Company last granted stock options in fiscal 2007 and all outstanding stock options have been fully vested since fiscal 2010.
SARs
Transactions involving SARs for all plans are summarized as follows:
The Company did not grant any SARs during the year ended September 30, 2014. The Company granted 412,970 SARs during the year ended September 30, 2013 with a weighted average grant date fair value of $10.66 per share. The SARs granted in 2013 may be settled in cash, in shares of common stock of the Company, or in a combination of cash and shares of common stock of the Company, as determined by the Company. The Company’s SARs include both performance based and non-performance based SARs, but the performance conditions associated with the performance based SARs at the time of grant have all been subsequently met. The SARs are
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considered equity awards under the current authoritative guidance for stock-based compensation. The accounting for SARs is the same as the accounting for stock options. The SARs granted during the year ended September 30, 2013 vest and become exercisable annually in one-third increments. The weighted average grant date fair value of the SARs granted during the year ended September 30, 2013 was estimated on the date of grant using the same accounting treatment that is applied for stock options.
The total intrinsic value of SARs exercised during the years ended September 30, 2015, 2014 and 2013 totaled approximately $2.0 million, $8.4 million, and $0.8 million, respectively. For the years ended September 30, 2015, 2014 and 2013, 157,386 SARs, 323,188 SARs and 287,168 SARs, respectively, became fully vested. The total fair value of the SARs that became vested during each of the years ended September 30, 2015, 2014 and 2013 was approximately $1.7 million, $3.8 million and $3.6 million, respectively. As of September 30, 2015, unrecognized compensation expense related to SARs totaled approximately $0.1 million, which will be recognized over a weighted average period of 6 months.
The fair value of SARs at the date of grant was estimated using the Black-Scholes-Merton closed form model. The risk-free interest rate is based on the yield of a Treasury Note with a remaining term commensurate with the expected term of the SARs. The expected life is based on historical experience and the expected volatility is based on historical daily stock price returns. For SARs grants during the year ended September 30, 2013, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees. The following weighted average assumptions were used in estimating the fair value of SARs at the date of grant:
Restricted Share Awards
Transactions involving restricted share awards for all plans are summarized as follows:
The Company did not grant any restricted share awards (non-vested stock as defined by the current accounting literature) during the years ended September 30, 2014 and 2013. As of September 30, 2015, unrecognized compensation expense related to restricted share awards totaled approximately $0.9 million, which will be recognized over a weighted average period of 2.4 years.
Vesting restrictions for the outstanding shares of non-vested restricted stock at September 30, 2015 will lapse as follows: 2016 - 5,000 shares; 2018 - 35,000 shares; and 2021 - 20,000 shares.
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Restricted Stock Units
Transactions involving non-performance based restricted stock units for all plans are summarized as follows:
The Company also granted 82,151 and 44,200 non-performance based restricted stock units during the years ended September 30, 2014 and 2013, respectively. The weighted average fair value of such non-performance based restricted stock units granted in 2014 and 2013 was $65.24 per share and $51.11 per share, respectively. As of September 30, 2015, unrecognized compensation expense related to non-performance based restricted stock units totaled approximately $5.7 million, which will be recognized over a weighted average period of 1.6 years.
Vesting restrictions for the non-performance based restricted stock units outstanding at September 30, 2015 will lapse as follows: 2016 - 77,837 units; 2017 - 76,156 units; 2018 - 50,600 units; 2019 - 21,245 units; and 2020 - 11,110 units.
Transactions involving performance based restricted stock units for all plans are summarized as follows:
The Company granted 255,604 performance based restricted stock units during the year ended September 30, 2013 with a weighted average grant date fair value of $49.51 per share. The Company did not grant any performance based restricted stock units during the year ended September 30, 2014. The performance based restricted stock units granted during the year ended September 30, 2013 must meet a performance condition over the performance cycle of October 1, 2012 to September 30, 2015. The performance condition over the performance cycle, generally stated, is the Company’s total return on capital as compared to the same metric for companies in the Natural Gas Distribution and Integrated Natural Gas Companies group as calculated and reported in the Monthly Utility Reports of AUS, Inc., a leading industry consultant. The number of performance based restricted stock units that will vest will depend upon the Company’s performance relative to the report group and not upon the absolute level of return achieved by the Company. Based on the significant loss that the Company experienced during 2015, management believes that the performance conditions associated with the outstanding performance based restricted stock units will not be met. Accordingly, the cumulative stock-based compensation expense of approximately $8.0 million associated with these restricted stock units was reversed during 2015, and there is no unrecognized compensation expense related to such performance based restricted stock units at September 30, 2015. These restricted stock units are not expected to vest in 2016, which is when the vesting restrictions are scheduled to lapse.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Performance Shares
Transactions involving performance shares for all plans are summarized as follows:
The Company granted 116,090 performance shares during the year ended September 30, 2014 with a weighted average grant date fair value of $67.16 per share. The Company did not grant any performance shares during the year ended September 30, 2013. As of September 30, 2015, unrecognized compensation expense related to performance shares totaled approximately $7.0 million, which will be recognized over a weighted average period of 1.3 years. Vesting restrictions for the outstanding performance shares at September 30, 2015 will lapse as follows: 2017 - 97,698 shares; and 2018 - 107,044 shares.
Half of the performance shares granted during the year ended September 30, 2015 must meet a performance goal related to relative return on capital over the performance cycle of October 1, 2014 to September 30, 2017. In addition, half of the performance shares granted during the year ended September 30, 2014 must meet a performance goal related to relative return on capital over the performance cycle of October 1, 2013 to September 30, 2016. The performance goals over their respective performance cycles for these performance shares granted during 2015 and 2014 is the Company’s total return on capital relative to the total return on capital of other companies in a group selected by the Compensation Committee (“Report Group”). Total return on capital for a given company means the average of the Report Group companies’ returns on capital for each twelve month period corresponding to each of the Company’s fiscal years during the performance cycle, based on data reported for the Report Group companies in the Bloomberg database. The number of these performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value of these performance shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award. The fair value is recorded as compensation expense over the vesting term of the award.
The other half of the performance shares granted during the year ended September 30, 2015 must meet a performance goal related to relative total shareholder return over the performance cycle of October 1, 2014 to September 30, 2017. In addition, the other half of the performance shares granted during the year ended September 30, 2014 must meet a performance goal related to relative total shareholder return over the performance cycle of October 1, 2013 to September 30, 2016. The performance goals over their respective performance cycles for these total shareholder return performance shares ("TSR performance shares") granted during 2015 and 2014 is the Company’s three-year total shareholder return relative to the three-year total shareholder return of the other companies in the Report Group. Three-year shareholder return for a given company will be based on the data reported for that company (with the starting and ending stock prices over the performance cycle calculated as the average closing stock price for the prior calendar month and with dividends reinvested in that company’s securities at each ex-dividend date) in the Bloomberg database. The number of these TSR performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value price at the date of grant for the TSR performance shares is determined using a Monte Carlo simulation technique, which includes a reduction in value for the present value
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of forgone dividends over the vesting term of the award. This price is multiplied by the number of TSR performance shares awarded, the result of which is recorded as compensation expense over the vesting term of the award. In calculating fair value of the award, the risk-free interest rate is based on the yield of a Treasury Note with a term commensurate with the remaining term of the TSR performance shares. The remaining term is based on the remainder of the performance cycle as of the date of grant. The expected volatility is based on historical daily stock price returns. For the TSR performance shares, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees. The following assumptions were used in estimating the fair value of the TSR performance shares at the date of grant:
Redeemable Preferred Stock
As of September 30, 2015, there were 10,000,000 shares of $1 par value Preferred Stock authorized but unissued.
Long-Term Debt
The outstanding long-term debt is as follows:
(1)
The Medium-Term Notes and Notes are unsecured.
(2)
None of the Company’s long-term debt at September 30, 2015 and 2014 will mature within the following twelve-month period.
(3)
The holders of these notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade.
On June 25, 2015, the Company issued $450.0 million of 5.20% notes due July 15, 2025. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $444.6 million. The proceeds of this debt issuance were used for general corporate purposes, including the reduction of short-term debt.
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As of September 30, 2015, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: zero in 2016 and 2017, $300.0 million in 2018, $250.0 million in 2019, zero in 2020 and $1,549.0 million thereafter.
Short-Term Borrowings
The Company historically has obtained short-term funds either through bank loans or the issuance of commercial paper. On December 5, 2014, the Company entered into an Amended and Restated Credit Agreement with a syndicate of 14 banks. The agreement replaced the Company's previous $750.0 million syndicated committed credit facility with a substantially similar facility totaling $750.0 million. On September 30, 2015, the Company entered into a Second Amended and Restated Credit Agreement (Credit Agreement) with a syndicate of the same 14 banks. This Credit Agreement provides a $750.0 million multi-year unsecured committed revolving credit facility through December 5, 2019, plus a $500.0 million 364-day unsecured committed revolving credit facility through September 29, 2016. The Company also has a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under the uncommitted lines of credit are made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. The total amount available to be issued under the Company’s commercial paper program is $500.0 million. At September 30, 2015, the commercial paper program was backed by the Credit Agreement.
The Company did not have any outstanding commercial paper at September 30, 2015. At September 30, 2014, the Company had outstanding commercial paper of $85.6 million with a weighted average interest rate on the commercial paper of 0.31%. The Company did not have any short-term notes payable to banks at September 30, 2015 and 2014.
Debt Restrictions
The Credit Agreement provides that the Company's debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter through December 5, 2019. At September 30, 2015, the Company’s debt to capitalization ratio (as calculated under the facility) was .51. The constraints specified in the Credit Agreement would have permitted an additional $1.67 billion in short-term and/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded .65.
If a downgrade in any of the Company’s credit ratings were to occur, access to the commercial paper markets might not be possible. However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources, including cash provided by operations.
The Credit Agreement contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more, or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of September 30, 2015, the Company had no debt outstanding under the Credit Agreement.
Under the Company’s existing indenture covenants, at September 30, 2015, the Company is precluded from issuing additional long-term unsecured indebtedness during fiscal 2016 as a result of impairments of its oil and gas properties recognized during the year ended September 30, 2015. The 1974 indenture would not preclude the Company from issuing new indebtedness to replace maturing debt. If the Company experiences additional significant impairments of its oil and gas properties in the first or subsequent quarters of fiscal 2016, the Company,
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under its 1974 indenture, expects to continue to be precluded from issuing incremental long-term debt into the first or subsequent quarters of fiscal 2017. However, the Company expects that it could borrow under its credit facilities. The Company's present liquidity position is believed to be adequate to satisfy known demands.
The Company’s 1974 indenture pursuant to which $99.0 million (or 4.7%) of the Company’s long-term debt (as of September 30, 2015) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement, or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.
Note F - Fair Value Measurements
The FASB authoritative guidance regarding fair value measurements establishes a fair-value hierarchy and prioritizes the inputs used in valuation techniques that measure fair value. Those inputs are prioritized into three levels. Level 1 inputs are unadjusted quoted prices in active markets for assets or liabilities that the Company can access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly at the measurement date. Level 3 inputs are unobservable inputs for the asset or liability at the measurement date. The Company’s 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 placement within the fair value hierarchy levels.
The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of September 30, 2015 and 2014. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The fair value presentation for over the counter swaps combines gas and oil swaps because a significant number of the counterparties enter into both gas and oil swap agreements with the Company.
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(1)
Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.
Derivative Financial Instruments
At September 30, 2015 and 2014, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX and ICE futures contracts used in the Company’s Energy Marketing segment. Hedging collateral deposits of $11.1 million (at September 30, 2015) and $2.7 million (at September 30, 2014), which are associated with these futures contracts, have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 at September 30, 2015 and 2014 consist of natural gas price swap agreements used in the Company’s Exploration and Production and Energy Marketing segments, the majority of the crude oil price swap agreements used in the Company’s Exploration and Production segment and foreign currency contracts used in the Company's Exploration and Production segment. The fair value of the Level 2 price swap agreements is based on an internal, discounted cash flow model that uses observable inputs (i.e. LIBOR based discount rates and basis differential information, if applicable, at active natural gas and crude oil trading markets). The fair value of the Level 2 foreign currency contracts is determined using the market approach based on observable market transactions of forward Canadian currency rates. The derivative financial instruments reported in Level 3 consist of a portion of the crude oil price swap agreements used in the Company’s Exploration and Production segment at September 30, 2015 and 2014. The fair value of the Level 3 crude oil price swap agreements is based on an internal, discounted cash flow model that uses both observable (i.e. LIBOR based discount rates) and unobservable inputs (i.e. basis differential information of crude oil trading markets with low trading volume).
The significant unobservable input used in the fair value measurement of a portion of the Company’s over-the-counter crude oil swaps is the basis differential between Midway Sunset oil and NYMEX contracts. Significant changes in the assumed basis differential could result in a significant change in the value of the derivative financial instruments. At September 30, 2015, it was assumed that Midway Sunset oil was 91.8% of NYMEX. This is based on a historical twelve month average of Midway Sunset oil sales verses NYMEX settlements. During this twelve-month period, the price of Midway Sunset oil ranged from 87.8% to 94.6% of NYMEX. If the price of Midway Sunset oil relative to NYMEX used in the fair value measurement calculation had been 10 percentage points higher, the fair value of the Level 3 crude oil price swap agreements asset would have been approximately $0.2 million lower at September 30, 2015. If the price of Midway Sunset oil relative to NYMEX used in the fair value measurement had been 10 percentage points lower, the fair value measurement of the Level 3 crude oil price swap agreements asset would have been approximately $0.2 million higher at September 30, 2015. These calculated amounts are based solely on basis differential changes and do not take into account any other changes to the fair value measurement calculation.
The accounting rules for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At September 30, 2015, the Company determined that nonperformance risk would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.
The tables listed below provide reconciliations of the beginning and ending net balances for assets and liabilities measured at fair value and classified as Level 3 for the years ended September 30, 2015 and September 30, 2014, respectively. For the years ended September 30, 2015 and September 30, 2014, no transfers in or out of Level 1 or Level 2 occurred. There were no purchases or sales of derivative financial instruments during the periods presented in the tables below. All settlements of the derivative financial instruments are reflected in the Gains/
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Losses Realized and Included in Earnings column of the tables below (amounts in parentheses indicate credits in the derivative asset/liability accounts).
Fair Value Measurements Using Unobservable Inputs (Level 3)
(1)
Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the year ended September 30, 2015.
(2)
Derivative Financial Instruments are shown on a net basis.
(1)
Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the year ended September 30, 2014.
(2)
Derivative Financial Instruments are shown on a net basis.
Note G - Financial Instruments
Long-Term Debt
The fair market value of the Company’s debt, as presented in the table below, was determined using a discounted cash flow model, which incorporates the Company’s credit ratings and current market conditions in determining the yield, and subsequently, the fair market value of the debt. Based on these criteria, the fair market value of long-term debt, including current portion, was as follows:
The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Carrying amounts for other financial instruments recorded on the Company’s Consolidated Balance Sheets approximate fair value. The fair value of long-term debt was calculated using observable inputs (U.S.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Treasuries/LIBOR for the risk-free component and company specific credit spread information - generally obtained from recent trade activity in the debt). As such, the Company considers the debt to be Level 2.
Any temporary cash investments, notes payable to banks and commercial paper are stated at cost. Temporary cash investments are considered Level 1, while notes payable to banks and commercial paper are considered to be Level 2. Given the short-term nature of the notes payable to banks and commercial paper, the Company believes cost is a reasonable approximation of fair value.
Other Investments
Investments in life insurance are stated at their cash surrender values or net present value as discussed below. Investments in an equity mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices.
Other investments include cash surrender values of insurance contracts (net present value in the case of split-dollar collateral assignment arrangements) and marketable equity and fixed income securities. The values of the insurance contracts amounted to $45.3 million and $44.4 million at September 30, 2015 and 2014, respectively. The fair value of the equity mutual fund was $34.9 million and $35.3 million at September 30, 2015 and 2014, respectively. The gross unrealized gain on this equity mutual fund was $6.5 million at September 30, 2015 and $8.4 million at September 30, 2014. The fair value of the fixed income mutual fund was $8.0 million at September 30, 2015. The fair value of the stock of an insurance company was $4.3 million and $6.6 million at September 30, 2015 and 2014, respectively. The gross unrealized gain on this stock was $2.6 million and $4.5 million at September 30, 2015 and 2014, respectively. The insurance contracts and marketable equity and fixed income securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.
Derivative Financial Instruments
The Company uses derivative financial instruments to manage commodity price risk in the Exploration and Production segment as well as the Energy Marketing segment. The Company enters into futures contracts and over-the-counter swap agreements for natural gas and crude oil to manage the price risk associated with forecasted sales of gas and oil. In addition, the Company also enters into foreign exchange forward contracts to manage the risk of currency fluctuations associated with transportation costs denominated in Canadian currency in the Exploration and Production segment. These instruments are accounted for as cash flow hedges. The Company also enters into futures contracts and swaps, which are accounted for as cash flow hedges, to manage the price risk associated with forecasted gas purchases. The Company enters into futures contracts and swaps to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and the decline in value of natural gas held in storage. These instruments are accounted for as fair value hedges. The duration of the Company’s combined cash flow and fair value hedges does not typically exceed 5 years. The Exploration and Production segment holds the majority of the Company’s derivative financial instruments. The derivative financial instruments held by the Energy Marketing segment are not considered to be material to the Company.
The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at September 30, 2015 and September 30, 2014. Substantially all of the derivative financial instruments reported on those line items relate to commodity contracts and a small portion relates to foreign currency contracts.
Cash Flow Hedges
For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings. Gains and losses on
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the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.
As of September 30, 2015, the Company had the following commodity derivative contracts (swaps and futures contracts) outstanding:
As of September 30, 2015, the Company was hedging a total of $58.0 million of forecasted transportation costs denominated in Canadian dollars with swaps on forward currency rates (long positions). Settlements will begin in fiscal 2016.
As of September 30, 2015, the Company had $272.2 million ($157.2 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that $168.1 million ($97.1 million after tax) of such unrealized gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings.
Refer to Note A, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain (loss) pertaining to derivative financial instruments.
Fair Value Hedges
The Company utilizes fair value hedges to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and the decline in the value of certain natural gas held in storage. With respect to
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
fixed price sales commitments, the Company enters into long positions to mitigate the risk of price increases for natural gas supplies that could occur after the Company enters into fixed price sales agreements with its customers. With respect to fixed price purchase commitments, the Company enters into short positions to mitigate the risk of price decreases that could occur after the Company locks into fixed price purchase deals with its suppliers. With respect to storage hedges, the Company enters into short positions to mitigate the risk of price decreases that could result in a lower of cost or market writedown of the value of natural gas in storage that is recorded in the Company’s financial statements. As of September 30, 2015, the Company’s Energy Marketing segment had fair value hedges covering approximately 17.9 Bcf of mostly fixed price sales commitments. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below.
Credit Risk
The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over-the-counter swap positions with sixteen counterparties of which fifteen are in a net gain position. On average, the Company had $18.0 million of credit exposure per counterparty in a gain position at September 30, 2015. The maximum credit exposure per counterparty in a gain position at September 30, 2015 was $50.5 million. The Company’s gain position on such derivative financial instruments for certain counterparties exceeded the established thresholds at which the counterparties would be required to post collateral. At September 30, 2015, collateral deposits of $29.7 million were posted. These collateral deposits are recorded as a component of Accounts Payable on the Consolidated Balance Sheet.
As of September 30, 2015, thirteen of the sixteen counterparties to the Company’s outstanding derivative instrument contracts (specifically the over-the-counter swaps) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative instrument contracts were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then additional hedging collateral deposits may be required. At September 30, 2015, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $174.6 million according to the Company’s internal model (discussed in Note F - Fair Value Measurements). For its over-the-counter swap agreements, no hedging collateral deposits were required to be posted by the Company at September 30, 2015.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
For its exchange traded futures contracts, the Company was required to post $11.1 million in hedging collateral deposits as of September 30, 2015. As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts hedging collateral based on open positions and margin requirements it has with its counterparties.
The Company’s requirement to post hedging collateral deposits and the Company's right to receive hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value. Hedging collateral deposits may also include closed derivative positions in which the broker has not cleared the cash from the account to offset the derivative liability. The Company records liabilities related to closed derivative positions in Other Accruals and Current Liabilities on the Consolidated Balance Sheet. These liabilities are relieved when the broker clears the cash from the hedging collateral deposit account. This is discussed in Note A under Hedging Collateral Deposits.
Note H - Retirement Plan and Other Post-Retirement Benefits
The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Retirement Plan). The Retirement Plan covers certain non-collectively bargained employees hired before July 1, 2003 and certain collectively bargained employees hired before November 1, 2003. Certain non-collectively bargained employees hired after June 30, 2003 and certain collectively bargained employees hired after October 31, 2003 are eligible for a Retirement Savings Account benefit provided under the Company’s defined contribution Tax-Deferred Savings Plans. Costs associated with the Retirement Savings Account were $2.3 million, $1.9 million and $1.2 million for the years ended September 30, 2015, 2014 and 2013, respectively. Costs associated with the Company’s contributions to the Tax-Deferred Savings Plans, exclusive of the costs associated with the Retirement Savings Account, were $5.8 million, $5.2 million, and $4.4 million for the years ended September 30, 2015, 2014 and 2013, respectively.
The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The other post-retirement benefits cover certain non-collectively bargained employees hired before January 1, 2003 and certain collectively bargained employees hired before October 31, 2003.
The Company’s policy is to fund the Retirement Plan with at least an amount necessary to satisfy the minimum funding requirements of applicable laws and regulations and not more than the maximum amount deductible for federal income tax purposes. The Company has established VEBA trusts for its other post-retirement benefits. Contributions to the VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code and regulations and are made to fund employees’ other post-retirement benefits, as well as benefits as they are paid to current retirees. In addition, the Company has established 401(h) accounts for its other post-retirement benefits. They are separate accounts within the Retirement Plan trust used to pay retiree medical benefits for the associated participants in the Retirement Plan. Although these accounts are in the Retirement Plan trust, for funding status purposes as shown below, the 401(h) accounts are included in Fair Value of Assets under Other Post-Retirement Benefits. Contributions are tax-deductible when made, subject to limitations contained in the Internal Revenue Code and regulations.
The expected return on Retirement Plan assets, a component of net periodic benefit cost shown in the tables below, is applied to the market-related value of plan assets. The market-related value of plan assets is the market value as of the measurement date adjusted for variances between actual returns and expected returns (from previous years) that have not been reflected in net periodic benefit costs. The expected return on other post-retirement benefit assets (i.e. the VEBA trusts and 401(h) accounts), which is a component of net periodic benefit cost shown in the tables below, is applied to the fair value of assets as of the measurement date.
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Reconciliations of the Benefit Obligations, Plan Assets and Funded Status, as well as the components of Net Periodic Benefit Cost and the Weighted Average Assumptions of the Retirement Plan and other post-retirement benefits are shown in the tables below. The date used to measure the Benefit Obligations, Plan Assets and Funded Status is September 30 for fiscal years 2015, 2014 and 2013.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(1)
In fiscal 2015, the Company passed an amendment which updated the mortality table used in the Retirement Plan's definition of "actuarially equivalent" effective July 1, 2015. This increased the benefit obligation of the Retirement Plan.
(2)
Distribution Corporation’s New York jurisdiction calculates the amortization of the actuarial loss on a vintage year basis over 10 years, as mandated by the NYPSC. All the other subsidiaries of the Company utilize the corridor approach.
The Net Periodic Benefit Cost in the table above includes the effects of regulation. The Company recovers pension and other post-retirement benefit costs in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorizations. Certain of those commission authorizations established tracking mechanisms which allow the Company to record the difference between the amount of pension and other post-retirement benefit costs recoverable in rates and the amounts of such costs as determined under the existing authoritative guidance as either a regulatory asset or liability, as appropriate. Any activity under the tracking mechanisms (including the amortization of pension and other post-retirement regulatory assets and liabilities) is reflected in the Net Amortization and Deferral for Regulatory Purposes line item above.
In addition to the Retirement Plan discussed above, the Company also has Non-Qualified benefit plans that cover a group of management employees designated by the Chief Executive Officer of the Company. These plans provide for defined benefit payments upon retirement of the management employee, or to the spouse upon death of the management employee. The net periodic benefit cost associated with these plans were $7.0 million, $7.5 million and $9.6 million in 2015, 2014 and 2013, respectively. The accumulated benefit obligations for the plans were $66.0 million, $65.7 million and $57.2 million at September 30, 2015, 2014 and 2013, respectively. The projected benefit obligations for the plans were $85.8 million, $85.5 million and $77.1 million at September 30, 2015, 2014 and 2013, respectively. At September 30, 2015, $4.5 million of the projected benefit obligation is recorded in Other Accruals and Current Liabilities and the remaining $81.3 million is recorded in Other Deferred
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Credits on the Consolidated Balance Sheets. At September 30, 2014, $6.6 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $78.9 million was recorded in Other Deferred Credits on the Consolidated Balance Sheets. At September 30, 2013, the projected benefit obligations are recorded in Other Deferred Credits on the Consolidated Balance Sheets. The weighted average discount rates for these plans were 3.50%, 3.50% and 3.75% as of September 30, 2015, 2014 and 2013, respectively and the weighted average rate of compensation increase for these plans were 7.75%, 7.50% and 7.75% as of September 30, 2015, 2014 and 2013, respectively.
The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal 2015, the changes in such amounts during 2015, as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 2016 are presented in the table below:
(1)
Amounts presented are shown before recognizing deferred taxes.
(2)
Amounts presented include the impact of actuarial gains/losses related to return on assets, as well as the Actuarial (Gain) Loss amounts presented in the Change in Benefit Obligation.
In order to adjust the funded status of its pension (tax-qualified and non-qualified) and other post-retirement benefit plans at September 30, 2015, the Company recorded a $76.7 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $22.3 million (pre-tax) decrease to Accumulated Other Comprehensive Income.
The effect of the mortality assumption change for the Retirement Plan in 2015 was to increase the projected benefit obligation of the Retirement Plan by $24.2 million. In 2015, other actuarial experience decreased the projected benefit obligation for the Retirement Plan by $0.8 million. The effect of the discount rate change for the Retirement Plan in 2014 was to increase the projected benefit obligation of the Retirement Plan by $53.7 million. The effect of the discount rate change for the Retirement Plan in 2013 was to decrease the projected benefit obligation of the Retirement Plan by $147.9 million.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Company made cash contributions totaling $36.2 million to the Retirement Plan during the year ended September 30, 2015. The Company expects that the annual contribution to the Retirement Plan in 2016 will be in the range of $5.0 million to $10.0 million.
The following Retirement Plan benefit payments, which reflect expected future service, are expected to be paid by the Retirement Plan during the next five years and the five years thereafter: $61.1 million in 2016; $62.1 million in 2017; $63.0 million in 2018; $63.7 million in 2019; $64.4 million in 2020; and $332.1 million in the five years thereafter.
The effect of the discount rate change in 2015 was to decrease the other post-retirement benefit obligation by $14.3 million. Other actuarial experience increased the other post-retirement benefit obligation in 2015 by $12.8 million primarily attributable to the change in mortality assumption.
The effect of the discount rate change in 2014 was to increase the other post-retirement benefit obligation by $26.4 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2014 by $25.3 million primarily attributable to a revision in assumed per-capita claims cost, premiums and participant contributions based on actual experience.
The effect of the discount rate change in 2013 was to decrease the other post-retirement benefit obligation by $75.9 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2013 by $28.6 million as the increase in obligation attributable to the change in mortality assumption was more than offset by the decrease in obligation attributable to a revision in assumed per-capita claims cost, premiums and participant contributions based on actual experience.
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 provides for a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.
The estimated gross other post-retirement benefit payments and gross amount of Medicare Part D prescription drug subsidy receipts are as follows (dollars in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Assumed health care cost trend rates as of September 30 were:
(1)
It was assumed that this rate would gradually decline to 4.5% by 2028.
The health care cost trend rate assumptions used to calculate the per capita cost of covered medical care benefits have a significant effect on the amounts reported. If the health care cost trend rates were increased by 1% in each year, the other post-retirement benefit obligation as of October 1, 2015 would increase by $53.9 million. This 1% change would also have increased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 2015 by $2.9 million. If the health care cost trend rates were decreased by 1% in each year, the other post-retirement benefit obligation as of October 1, 2015 would decrease by $45.2 million. This 1% change would also have decreased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 2015 by $2.4 million.
The Company made cash contributions totaling $2.0 million to its VEBA trusts and 401(h) accounts during the year ended September 30, 2015. In addition, the Company made direct payments of $0.2 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2015. The Company expects that the annual contribution to its VEBA trusts and 401(h) accounts in 2016 will be in the range of $2.0 million to $5.0 million.
Investment Valuation
The Retirement Plan assets and other post-retirement benefit assets are valued under the current fair value framework. See Note F - Fair Value Measurements for further discussion regarding the definition and levels of fair value hierarchy established by the authoritative guidance.
The inputs or methodologies used for valuing securities are not necessarily an indication of the risk associated with investing in those securities. Below is a listing of the major categories of plan assets held as of September 30, 2015 and 2014, as well as the associated level within the fair value hierarchy in which the fair value measurements in their entirety fall, based on the lowest level input that is significant to the fair value measurement in its entirety (dollars in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(1)
Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds.
(2)
International Equities include mostly collective trust funds and common stock.
(3)
Global Equities are comprised of collective trust funds.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(4)
Domestic Fixed Income securities include mostly collective trust funds, corporate/government bonds and mortgages, and exchange traded funds.
(5)
International Fixed Income securities include mostly collective trust funds and exchange traded funds.
(6)
Global Fixed Income securities are comprised of a collective trust fund.
The fair values disclosed in the above tables may not be indicative of net realizable value or reflective of future fair values. Furthermore, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.
The following tables provide a reconciliation of the beginning and ending balances of the Retirement Plan and other post-retirement benefit assets measured at fair value on a recurring basis where the determination of fair
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
value includes significant unobservable inputs (Level 3). Note: For the years ended September 30, 2015 and September 30, 2014, there were no transfers from Level 1 to Level 2. In addition, as shown in the following tables, there were no transfers in or out of Level 3.
The Company’s assumption regarding the expected long-term rate of return on plan assets is 7.25% (Retirement Plan) and 6.75% (other post-retirement benefits), effective for fiscal 2016. The return assumption reflects the anticipated long-term rate of return on the plan’s current and future assets. The Company utilizes projected capital market conditions and the plan’s target asset class and investment manager allocations to set the assumption regarding the expected return on plan assets.
The long-term investment objective of the Retirement Plan trust, the VEBA trusts and the 401(h) accounts is to achieve the target total return in accordance with the Company’s risk tolerance. Assets are diversified utilizing
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
a mix of equities, fixed income and other securities (including real estate). The target allocation for the Retirement Plan and the VEBA trusts (including 401(h) accounts) is 40-60% equity securities, 40-60% fixed income securities and 0-15% other. Risk tolerance is established through consideration of plan liabilities, plan funded status and corporate financial condition. The assets of the Retirement Plan trusts, VEBA trusts and the 401(h) accounts have no significant concentrations of risk in any one country (other than the United States), industry or entity.
Investment managers are retained to manage separate pools of assets. Comparative market and peer group performance of individual managers and the total fund are monitored on a regular basis, and reviewed by the Company’s Retirement Committee on at least a quarterly basis.
The discount rate used to present value the future benefit payment obligations of the Retirement Plan is 4.25% at September 30, 2015. The discount rate used to present value the future benefit payment obligations of the Company’s other post-retirement benefits is 4.50% as of September 30, 2015. The discount rate used to present value the future benefit payment obligations of the Non-Qualified benefit plans is 3.50% as of September 30, 2015. The Company utilizes the Mercer Yield Curve Above Mean Model to determine the discount rate. The yield curve is a spot rate yield curve that provides a zero-coupon interest rate for each year into the future. Each year’s anticipated benefit payments are discounted at the associated spot interest rate back to the measurement date. The discount rate is then determined based on the spot interest rate that results in the same present value when applied to the same anticipated benefit payments. In determining the spot rates, the model will exclude coupon interest rates that are in the lower 50th percentile based on the assumption that the Company would not utilize more expensive (i.e. lower yield) instruments to settle its liabilities.
Note I - Commitments and Contingencies
Environmental Matters
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory requirements.
It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. At September 30, 2015, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be approximately $11.2 million. The main component of this liability is discussed below under "Former Manufactured Gas Plant Sites." This estimated liability has been recorded in Other Deferred Credits on the Consolidated Balance Sheet at September 30, 2015. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 12 years. Other than as discussed below, the Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental laws and regulations, new information or other factors could could have an adverse financial impact on the Company.
Former Manufactured Gas Plant Sites
The Company has incurred investigation and/or clean-up costs at several former manufactured gas plant sites in New York and Pennsylvania. The Company continues to be responsible for future ongoing monitoring and long-term maintenance at two sites.
The most significant ongoing clean-up matter currently facing the Company is a former manufactured gas plant site located in New York. In February 2009, the Company received approval from the NYDEC of a Remedial Design Work Plan (RDWP) for this site. In October 2010, the Company submitted a RDWP addendum to conduct additional Preliminary Design Investigation field activities necessary to design a successful remediation. As a result of this work, the Company submitted to the NYDEC a proposal to amend the NYDEC’s Record of Decision remedy for the site. In April 2013, the NYDEC approved the Company’s proposed amendment. Final remedial
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
design work for the site has been completed, and remedial work has begun. An estimated minimum liability for remaining remediation of this site of $9.9 million has been recorded.
Other
The Company, in its Utility segment, Energy Marketing segment, and Exploration and Production segment, has entered into contractual commitments in the ordinary course of business, including commitments to purchase gas, transportation, and storage service to meet customer gas supply needs. The majority of these contracts expire within the next five years. The future gas purchase, transportation and storage contract commitments during the next five years and thereafter are as follows: $185.1 million in 2016, $89.4 million in 2017, $84.9 million in 2018, $92.6 million in 2019, $73.5 million in 2020 and $762.5 million thereafter. Gas prices within the gas purchase contracts are variable based on NYMEX prices adjusted for basis. In the Utility segment, these costs are subject to state commission review, and are being recovered in customer rates. Management believes that, to the extent any stranded pipeline costs are generated by the unbundling of services in the Utility segment’s service territory, such costs will be recoverable from customers.
The Company has entered into leases for the use of compressors, drilling rigs, buildings, meters and other items. These leases are accounted for as operating leases. The future lease commitments during the next five years and thereafter are as follows: $25.7 million in 2016, $6.0 million in 2017, $4.7 million in 2018, $4.5 million in 2019, $3.3 million in 2020 and $0.6 million thereafter.
The Company, in its Pipeline and Storage segment and Gathering segment, has entered into several contractual commitments associated with various pipeline, compressor and gathering system expansion projects. As of September 30, 2015, the future contractual commitments related to the expansion projects are $96.6 million in 2016 and $0.2 million in 2017. There are no contractual commitments extending beyond 2017.
The Company, in its Exploration and Production segment, has entered into contractual obligations associated with hydraulic fracturing and fuel. The future contractual commitments are $104.7 million in 2016 and $25.0 million in 2017. There are no contractual commitments extending beyond 2017.
The Company, in its Utility segment, has entered into contractual obligations associated with the replacement of its legacy mainframe systems and has future contractual commitments of $21.4 million in 2016. There are no contractual commitments extending beyond 2016.
The Company is involved in other litigation arising in the normal course of business. In addition to the regulatory matters discussed in Note C - Regulatory Matters, the Company is involved in other regulatory matters arising in the normal course of business. These other litigation and regulatory matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these other matters arising in the normal course of business could have a material effect on earnings and cash flows in the period in which they are resolved, an estimate of the possible loss or range of loss, if any, cannot be made at this time.
Note J - Business Segment Information
The Company reports financial results for five segments: Exploration and Production, Pipeline and Storage, Gathering, Utility and Energy Marketing. The division of the Company’s operations into reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.
The Exploration and Production segment, through Seneca, is engaged in exploration for, and development and purchase of, natural gas and oil reserves in California and the Appalachian region of the United States.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Pipeline and Storage segment operations are regulated by the FERC for both Supply Corporation and Empire. Supply Corporation transports and stores natural gas for utilities (including Distribution Corporation), natural gas marketers (including NFR), exploration and production companies (including Seneca) and pipeline companies in the northeastern United States markets. Empire transports natural gas to major industrial companies, utilities (including Distribution Corporation) and power producers in New York State.
The Gathering segment is comprised of Midstream Corporation’s operations. Midstream Corporation builds, owns and operates natural gas processing and pipeline gathering facilities in the Appalachian region and currently provides gathering services to Seneca.
The Utility segment operations are regulated by the NYPSC and the PaPUC and are carried out by Distribution Corporation. Distribution Corporation sells natural gas to retail customers and provides natural gas transportation services in western New York and northwestern Pennsylvania.
The Energy Marketing segment is comprised of NFR’s operations. NFR markets natural gas to industrial, wholesale, commercial, public authority and residential customers primarily in western and central New York and northwestern Pennsylvania, offering competitively priced natural gas for its customers.
The data presented in the tables below reflects financial information for the segments and reconciliations to consolidated amounts. The accounting policies of the segments are the same as those described in Note A - Summary of Significant Accounting Policies. Sales of products or services between segments are billed at regulated rates or at market rates, as applicable. The Company evaluates segment performance based on income before discontinued operations, extraordinary items and cumulative effects of changes in accounting (when applicable). When these items are not applicable, the Company evaluates performance based on net income. Energy Marketing segment revenues and related purchased gas costs for the year ended September 30, 2013 were recorded when billed, resulting in a one month lag. Starting in 2014, the Energy Marketing segment began recording unbilled revenue and related gas costs, recording $8.5 million of unbilled revenue and $0.6 million of related incremental margin (net of tax). The impact of not recording unbilled revenue and related costs was immaterial in all prior periods.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(1)
All Revenue from External Customers originated in the United States.
Note K - Quarterly Financial Data (unaudited)
In the opinion of management, the following quarterly information includes all adjustments necessary for a fair statement of the results of operations for such periods. Per common share amounts are calculated using the weighted average number of shares outstanding during each quarter. The total of all quarters may differ from the per common share amounts shown on the Consolidated Statements of Income. Those per common share amounts are based on the weighted average number of shares outstanding for the entire fiscal year. Because of the seasonal nature of the Company’s heating business, there are substantial variations in operations reported on a quarterly basis.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(1)
Includes a non-cash $417.2 million impairment charge ($240.9 million after tax) associated with the Exploration and Production segment's oil and gas producing properties and a $8.0 million reversal of stock-based compensation expense ($5.2 million after tax) related to performance based restricted stock units.
(2)
Includes a non-cash $588.7 million impairment charge ($339.8 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
(3)
Includes a non-cash $120.3 million impairment charge ($69.5 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
(4)
Includes $3.6 million of income associated with a death benefit gain on life insurance proceeds recorded in the Corporate category.
Note L - Market for Common Stock and Related Shareholder Matters (unaudited)
At September 30, 2015, there were 12,147 registered shareholders of Company common stock. The common stock is listed and traded on the New York Stock Exchange. Information related to restrictions on the payment of dividends can be found in Note E - Capitalization and Short-Term Borrowings. The quarterly price ranges (based on intra-day prices) and quarterly dividends declared for the fiscal years ended September 30, 2015 and 2014, are shown below:
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note M - Supplementary Information for Oil and Gas Producing Activities (unaudited, except for Capitalized Costs Relating to Oil and Gas Producing Activities)
The Company follows authoritative guidance related to oil and gas exploration and production activities that aligns the reserve estimation and disclosure requirements with the requirements of the SEC Modernization of Oil and Gas Reporting rule, which the Company also follows. The SEC rules require companies to value their year-end reserves using an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve month period prior to the end of the reporting period.
The following supplementary information is presented in accordance with the authoritative guidance regarding disclosures about oil and gas producing activities and related SEC accounting rules. All monetary amounts are expressed in U.S. dollars.
Capitalized Costs Relating to Oil and Gas Producing Activities
(1)
Includes asset retirement costs of $113.3 million and $75.7 million at September 30, 2015 and 2014, respectively.
Costs related to unproved properties are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized. Although the timing of the ultimate evaluation or disposition of the unproved properties cannot be determined, the Company expects the majority of its acquisition costs associated with unproved properties to be transferred into the amortization base by 2020. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by 2016. Following is a summary of costs excluded from amortization at September 30, 2015:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
(1)
Amounts for 2015, 2014 and 2013 include capitalized interest of $0.4 million, $0.7 million and $0.4 million, respectively.
(2)
Amounts for 2015, 2014 and 2013 include capitalized interest of $0.5 million, $0.7 million and $0.7 million, respectively.
For the years ended September 30, 2015, 2014 and 2013, the Company spent $161.8 million, $179.9 million and $148.5 million, respectively, developing proved undeveloped reserves.
Results of Operations for Producing Activities
(1)
Exclusive of hedging gains and losses. See further discussion in Note G - Financial Instruments.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Reserve Quantity Information
The Company’s proved oil and gas reserve estimates are prepared by the Company’s reservoir engineers who meet the qualifications of Reserve Estimator per the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007. The Company maintains comprehensive internal reserve guidelines and a continuing education program designed to keep its staff up to date with current SEC regulations and guidance.
The Company’s Vice President of Reservoir Engineering is the primary technical person responsible for overseeing the Company’s reserve estimation process and engaging and overseeing the third party reserve audit. His qualifications include a Bachelor of Science Degree in Petroleum Engineering and over 25 years of Petroleum Engineering experience with both major and independent oil and gas companies. He has maintained oversight of the Company’s reserve estimation process for the past twelve years. He is a member of the Society of Petroleum Evaluation Engineers and a Registered Professional Engineer in the State of Texas.
The Company maintains a system of internal controls over the reserve estimation process. Management reviews the price, heat content, lease operating cost and future investment assumptions used in the economic model that determines the reserves. The Vice President of Reservoir Engineering reviews and approves all new reserve assignments and significant reserve revisions. Access to the reserve database is restricted. Significant changes to the reserve report are reviewed by senior management on a quarterly basis. Periodically, the Company’s internal audit department assesses the design of these controls and performs testing to determine the effectiveness of such controls.
All of the Company’s reserve estimates are audited annually by Netherland, Sewell and Associates, Inc. (NSAI). Since 1961, NSAI has evaluated gas and oil properties and independently certified petroleum reserve quantities in the United States and internationally under the Texas Board of Professional Engineers Registration No.. The primary technical persons (employed by NSAI) that are responsible for leading the audit include a professional engineer registered with the State of Texas (consulting at NSAI since 2004 and with over 5 years of prior industry experience in petroleum engineering) and a professional geoscientist registered in the State of Texas (consulting at NSAI since 1998 with over 13 years of prior industry experience in petroleum geosciences). NSAI was satisfied with the methods and procedures used by the Company to prepare its reserve estimates at September 30, 2015 and did not identify any problems which would cause it to take exception to those estimates.
The reliable technologies that were utilized in estimating the reserves include wire line open-hole log data, performance data, log cross sections, core data, 2D and 3D seismic data and statistical analysis. The statistical method utilized production performance from both the Company’s and competitors’ wells. Geophysical data includes data from the Company’s wells, published documents, state data-sites and 2D and 3D seismic data. This data was used to confirm continuity of the formation.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(1)
Extensions and discoveries include 355 Bcf (during 2013), 442 Bcf (during 2014) and 598 Bcf (during 2015), of Marcellus Shale gas in the Appalachian Region.
(2)
Production includes 93,999 MMcf (during 2013), 131,590 MMcf (during 2014) and 130,291 MMcf (during 2015), from Marcellus Shale fields (which exceed 15% of total reserves).
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Company’s proved undeveloped (PUD) reserves increased from 512 Bcfe at September 30, 2014 to 827 Bcfe at September 30, 2015. PUD reserves in the Marcellus Shale increased from 504 Bcfe at September 30, 2014 to 825 Bcfe at September 30, 2015. The Company’s total PUD reserves were 35% of total proved reserves at September 30, 2015, up from 27% of total proved reserves at September 30, 2014.
The Company’s PUD reserves increased from 452 Bcfe at September 30, 2013 to 512 Bcfe at September 30, 2014. PUD reserves in the Marcellus Shale increased from 432 Bcfe at September 30, 2013 to 504 Bcfe at September 30, 2014. The Company’s total PUD reserves were 27% of total proved reserves at September 30, 2014, down from 29% of total proved reserves at September 30, 2013.
The increase in PUD reserves in 2015 of 315 Bcfe is a result of 496 Bcfe in new PUD reserve additions (494 Bcfe from the Marcellus Shale), 26 Bcfe in upward revisions to remaining PUD reserves, offset by 168 Bcfe in PUD conversions to developed reserves and 39 Bcfe in PUD reserves removed. The PUD reserves removed were primarily in the Marcellus Shale (37 Bcfe) in Tioga County, where the Company has no near term plans to develop these reserves as it is employing capital elsewhere. An additional 2 Bcfe (279 Mbbl) of PUD reserves were removed
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
at the Midway Sunset field in the Tulare reservoir as the Company has no near term plans to develop these reserves as it is employing capital elsewhere.
The increase in PUD reserves in 2014 of 60 Bcfe is a result of 290 Bcfe in new PUD reserve additions (288 Bcfe from the Marcellus Shale), 20 Bcfe in PUD reserves acquired, 12 Bcfe in upward revisions to remaining PUD reserves, offset by 229 Bcfe in PUD conversions to developed reserves and 33 Bcfe in PUD reserves removed. The PUD reserves removed were primarily in the Marcellus Shale (24 Bcfe) in Seneca’s non-operated joint venture in Clearfield County where the operator had previously drilled and cased the horizontal wells to total depth and does not appear now to have firm plans for their completion. An additional 9 Bcfe (1,501 Mbbl) of PUD reserves were removed at the Midway Sunset field in the Tulare reservoir as the Company has no near term plans to develop these reserves as it is employing capital elsewhere.
The Company invested $162 million during the year ended September 30, 2015 to convert 168 Bcfe (184 Bcfe including revisions) of PUD reserves to developed reserves. This represents 33% of the PUD reserves booked at September 30, 2014. The Company invested $180 million during the year ended September 30, 2014 to convert 229 Bcfe (248 Bcfe including revisions) of September 30, 2013 PUD reserves to proved developed reserves. This represented 51% of the PUD reserves booked at September 30, 2013. In 2016, the Company estimates that it will invest approximately $166 million to develop its PUD reserves. The Company is committed to developing its PUD reserves within five years as required by the SEC’s final rule on Modernization of Oil and Gas Reporting. Since that rule, and over the last five years, the Company developed 47% of its beginning year PUD reserves in fiscal 2011, 33% of its beginning year PUD reserves in fiscal 2012, 39% of its beginning year PUD reserves in fiscal 2013, 51% of its beginning year PUD reserves in fiscal 2014 and 33% of its beginning year PUD reserves in fiscal 2015.
At September 30, 2015, the Company does not have a material concentration of proved undeveloped reserves that have been on the books for more than five years at the corporate level, country level or field level. All of the Company’s proved reserves are in the United States.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company’s oil and gas properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, in accordance with the SEC’s final rule on Modernization of Oil and Gas Reporting, it is based on the unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period and costs adjusted only for existing contractual changes. It assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under widely fluctuating political and economic conditions.
The standardized measure is intended instead to provide a means for comparing the value of the Company’s proved reserves at a given time with those of other oil- and gas-producing companies than is provided by a simple comparison of raw proved reserve quantities.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
Schedule II - Valuation and Qualifying Accounts
(1)
Represents the discount on accounts receivable purchased in accordance with the Utility segment’s 2005 New York rate agreement.
(2)
Amounts represent net accounts receivable written-off.
Item 9
Item 9
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A
Item 9A
Controls and Procedures
Evaluation of Disclosure Controls and Procedures
The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2015.
Management’s Annual Report on Internal Control over Financial Reporting
The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with GAAP. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of September 30, 2015. In making this assessment, management used the framework and criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework, published in 2013. Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of September 30, 2015.
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited the Company’s consolidated financial statements included in this Annual Report on Form 10-K, has issued an attestation report
on the effectiveness of the Company’s internal control over financial reporting as of September 30, 2015. The report appears in Part II, Item 8 of this Annual Report on Form 10-K.
Changes in Internal Control over Financial Reporting
There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended September 30, 2015 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 9B
Item 9B
Other Information
None.
PART III
Item 10
Item 10
Directors, Executive Officers and Corporate Governance
The information concerning directors will be set forth in the definitive Proxy Statement under the headings entitled “Nominees for Election as Directors for Three-Year Terms to Expire in 2019,” “Directors Whose Terms Expire in 2018,” “Directors Whose Terms Expire in 2017,” and “Section 16(a) Beneficial Ownership Reporting Compliance” and is incorporated herein by reference. The information concerning corporate governance will be set forth in the definitive Proxy Statement under the heading entitled “Meetings of the Board of Directors and Standing Committees” and is incorporated herein by reference. Information concerning the Company’s executive officers can be found in Part I, Item 1, of this report.
The Company has adopted a Code of Business Conduct and Ethics that applies to the Company’s directors, officers and employees and has posted such Code of Business Conduct and Ethics on the Company’s website, www.nationalfuelgas.com, together with certain other corporate governance documents. Copies of the Company’s Code of Business Conduct and Ethics, charters of important committees, and Corporate Governance Guidelines will be made available free of charge upon written request to Investor Relations, National Fuel Gas Company, 6363 Main Street, Williamsville, New York 14221.
The Company intends to satisfy the disclosure requirement under Item 5.05 of Form 8-K regarding an amendment to, or a waiver from, a provision of its code of ethics that applies to the Company’s principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions, and that relates to any element of the code of ethics definition enumerated in paragraph (b) of Item 406 of the SEC’s Regulation S-K, by posting such information on its website, www.nationalfuelgas.com.
The information concerning executive compensation will be set forth in the definitive Proxy Statement under the headings “Executive Compensation” and “Compensation Committee Interlocks and Insider Participation” and, excepting the “Report of the Compensation Committee,” is incorporated herein by reference.
Item 12
Item 12
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Equity Compensation Plan Information
The equity compensation plan information will be set forth in the definitive Proxy Statement under the heading “Equity Compensation Plan Information” and is incorporated herein by reference.
Security Ownership and Changes in Control
(a) Security Ownership of Certain Beneficial Owners
The information concerning security ownership of certain beneficial owners will be set forth in the definitive Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.
(b) Security Ownership of Management
The information concerning security ownership of management will be set forth in the definitive Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.
(c) Changes in Control
None.
Item 13
Item 13
Certain Relationships and Related Transactions, and Director Independence
The information regarding certain relationships and related transactions will be set forth in the definitive Proxy Statement under the headings “Compensation Committee Interlocks and Insider Participation” and “Related Person Transactions” and is incorporated herein by reference. The information regarding director independence is set forth in the definitive Proxy Statement under the heading “Director Independence” and is incorporated herein by reference.
Item 14
Item 14
Principal Accountant Fees and Services
The information concerning principal accountant fees and services will be set forth in the definitive Proxy Statement under the heading “Audit Fees” and is incorporated herein by reference.
PART IV
Item 15
Item 15
Exhibits and Financial Statement Schedules
(a)1.
Financial Statements
Financial statements filed as part of this report are listed in the index included in Item 8 of this Form 10-K, and reference is made thereto.
(a)2.
Financial Statement Schedules
Financial statement schedules filed as part of this report are listed in the index included in Item 8 of this Form 10-K, and reference is made thereto.
All documents referenced below were filed pursuant to the Securities Exchange Act of 1934 by National Fuel Gas Company (File No. 1-3880), unless otherwise noted.
Exhibit
Number
Description of
Exhibits
3(i)
Articles of Incorporation:
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
National Fuel Gas Company
(Registrant)
By
/s/ R. J. Tanski
R. J. Tanski
President and Chief Executive Officer
Date: November 20, 2015
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.