hifr-ex991_1227.htm

We have audited the accompanying consolidated financial statements of Sharyland Utilities, L.P. (the “Partnership”), which comprise the consolidated balance sheets as of December 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive income, partners’ capital, and cash flows for the years then ended and the related notes to the consolidated financial statements.

Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.

Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the 2015 financial statements of CV Project Entity, L.L.C. or GS Project Entity, L.L.C., wholly-owned subsidiaries, which statements reflect total assets constituting $257.5 million as of December 31, 2015. Those statements were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for CV Project Entity, L.L.C. and GS Project Entity, L.L.C., is based solely on the reports of the other auditors. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Sharyland Utilities, L.P. at December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the financial statements, the 2015 financial statements reflect retrospective application for the change in reporting entity. Our opinion is not modified with respect to this matter.

	December 31,
Assets	2016		2015
			(as adjusted)
Current Assets
Cash and cash equivalents	$	12,263	$	35,737
Accounts receivable, net		40,744		34,356
Due from affiliates		21,701		34,317
Inventory		1,380		—
Prepayments and other current assets		3,475		4,560
Total current assets		79,563		108,970
Property, Plant and Equipment - net		1,847,746		1,615,831
Goodwill		1,100		1,100
Deferred Charges – Regulatory Assets, net		41,807		37,758
Total Assets	$	1,970,216	$	1,763,659
Liabilities and Partners' Capital
Current Liabilities
Accounts payable and accrued liabilities	$	46,174	$	68,106
Current portion of long-term debt		3,493		—
Current portion of financing obligation		39,028		32,006
Due to affiliates		28,674		27,085
Fair value of derivative liabilities		—		32
State margin tax payable		1,756		1,545
Total current liabilities		119,125		128,774
Long-Term Financing Obligation - net of Deferred Financing Costs		1,555,797		1,371,502
Long-Term Debt		158,834		166,700
Regulatory Liabilities		6,907		5,940
OPEB and Other Liabilities		6,348		8,787
Total Liabilities		1,847,011		1,681,703
Commitments and Contingencies		—		1,163
Partners' Capital
General partner		1,181		756
Limited partner		122,024		80,069
Accumulated other comprehensive loss		—		(32	)
Total partners' capital		123,205		80,793
Total Liabilities and Partners' Capital	$	1,970,216	$	1,763,659

	Years Ended
	December 31,
	2016			2015
				(as adjusted)
Revenues	$	290,697		$	252,705
Operating Expenses
Distribution expense		21,941			28,844
Transmission expense		29,839			25,943
Administrative and general expense		40,430			39,822
Depreciation and amortization		41,636			32,099
Total operating expenses		133,846			126,708
Operating Income		156,851			125,997
Other Expense - net
Interest expense - net		(143,216	)		(129,902	)
Other income - net		2,985			4,809
Tax reimbursements for contributions in aid of construction		497			973
Total other expense - net		(139,734	)		(124,120	)
Net Income Before Income Taxes		17,117			1,877
Income Tax Expense		1,516			1,332
Net Income	$	15,601		$	545

Consolidated Statements of Partners’ Capital
Years Ended December 31, 2016 and 2015
(In thousands)

							Accumulated
							Other			Total
	General			Limited			Comprehensive			Partners'
	Partner			Partner			Loss			Capital
Balance at December 31, 2014	$	26		$	7,413		$	—		$	7,439
Partners' contributions		728			72,113			—			72,841
Net income		2			543			—			545
Change in fair value of
cash flow hedging instruments		—			—			(32	)		(32	)
Balance at December 31, 2015 - (as adjusted)		756			80,069			(32	)		80,793
Partners' contributions		298			29,481			—			29,779
Distributions to partners		(30	)		(2,970	)		—			(3,000	)
Net income		157			15,444			—			15,601
Change in fair value of
cash flow hedging instruments		—			—			32			32
Balance at December 31, 2016	$	1,181		$	122,024		$	—		$	123,205

	Years Ended
	December 31,
	2016			2015
				(as adjusted)
Cash flows from Operating Activities
Net income	$	15,601		$	545
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation		38,093			29,205
Amortization of deferred costs		4,749			3,986
Allowance for funds used during construction - equity		(2,930	)		(4,644	)
Realized loss in settlement of contingency		325			—
Changes in assets and liabilities:
Accounts receivable		(6,388	)		(1,546	)
Due from affiliates		12,616			(2,025	)
Inventory		(1,380	)		—
Prepayments and other current assets		(1,636	)		(2,865	)
Deferred charges - regulatory assets and liabilities		(7,460	)		5,703
Accounts payable, accrued liabilities and other		(10,160	)		3,640
Due to affiliates		1,589			5,086
State margin tax payable		211			(597	)
Commitment and contingencies		(1,488	)		—
Net cash provided by operating activities		41,742			36,488
Cash flows from Investing Activities
Additions to property, plant and equipment		(52,265	)		(161,584	)
Purchase of transmission plant under construction		—			(49,740	)
Net cash used in investing activities		(52,265	)		(211,324	)
Cash flows from Financing Activities
Partners' contributions		29,779			72,841
Distributions to partners		(3,000	)		—
Proceeds from short-term borrowing		17,000			5,000
Proceeds from short-term borrowing from affiliates		15,000			10,000
Proceeds from borrowing of long-term debt		16,500			166,700
Repayments of short-term borrowing		(17,000	)		(5,000	)
Repayments of short-term borrowing to affiliates		(15,000	)		(10,000	)
Repayments of long-term debt		(20,873	)		—
Deferred financing costs		—			(5,763	)
Repayments of financing obligation		(35,357	)		(30,588	)
Net cash (used in) provided by financing activities		(12,951	)		203,190
Net (decrease) increase in cash and cash equivalents		(23,474	)		28,354
Cash and cash equivalents at beginning of year		35,737			7,383
Cash and cash equivalents at end of year	$	12,263		$	35,737

Sharyland Utilities, L.P. (the Partnership or SULP) is a partnership engaged in providing regulated electric transmission and distribution delivery services to retail electric providers (REPs) serving over 54,000 electric delivery points in 29 counties in approximately 35,800 circuit miles of overhead and 4,700 circuit miles of underground distribution lines throughout Texas. The Partnership’s customers are principally residential, commercial and irrigation customers located in the cities of Mission and McAllen, Texas, in the outlying areas of Hidalgo County in south Texas, in the Midland-Stanton area of west Texas, in the central Texas area around Brady, and in northeast Texas in Hunt, Collin and Fannin Counties.

The Partnership is also engaged in the transmission of electricity throughout Texas. Those transmission activities include: a 138 Kilovolt (kV) looped system of approximately 323 circuit miles in length near Stanton; approximately 45 circuit miles 345 kV transmission line located near Stanton; a 138 kV direct current transmission interconnection between Texas and Mexico (Railroad DC Tie); approximately 16 circuit miles 138 kV transmission line located in the cities of Mission and McAllen; approximately 430 circuit miles 345 kV transmission loop in the Texas Panhandle and South Plains near Amarillo, Texas; a 55 circuit miles 345 kV transmission line between Golden Spread Electric Co-op and the White River Station in the Texas Panhandle; and approximately 48 circuit miles 345 kV transmission line from the eastern half of the North Edinburg substation to the Palmito substation in the southern region of Texas near Brownsville.

The Partnership was organized as a Texas limited partnership on November 3, 1998, as an electrical distribution utility located in Hidalgo County, Texas. Effective May 8, 2015, SU FERC, L.L.C., a subsidiary of the Partnership was merged with and into SULP as approved by the Public Utility Commission of Texas (PUCT) pursuant to Docket No. 43589. Immediately following the merger of SU FERC, L.L.C. into SULP, the Partnership created a new wholly owned subsidiary, also named SU FERC, L.L.C. On March 24, 2016, the Partnership transferred its ownership on SU FERC, L.L.C. to its General Partner.

On March 18, 2016, Hunt Power, L.P. (HP), an affiliate of the Partnership, contributed GS Project Entity, L.L.C. (GSPE) to the partners of the Partnership (Partners). The Partners contributed the interest in GSPE to the Partnership. GSPE became a wholly owned subsidiary of the Partnership. On May 6, 2016, HP also contributed CV Project Entity, L.L.C. (CVPE) to the Partners. The Partners contributed the interest in CVPE to the Partnership. CVPE became a wholly owned subsidiary of the Partnership. See Note 2.

The Partnership leases most of its transmission and distribution assets from a related party, Sharyland Distribution & Transmission Services, L.L.C. (SDTS) under Master Lease Agreements. See Note 3.

All significant intercompany balances and transactions have been eliminated. The Partnership maintains accounting records in accordance with the uniform system of accounts, as prescribed by the Federal Energy Regulatory Commission (FERC). The Partnership’s consolidated financial statements reflect the effects of the different rate making principles mandated by the FERC and PUCT regulating its operations.

The Partnership accounted for the contributions of GSPE and CVPE as common control transactions whereby the net assets acquired are combined with the Partnership at their carrying value. Prior period Consolidated Balance Sheet, Consolidated Statement of Operations, Consolidated Statement of Partner’s Capital and Consolidated Statement of Cash Flows, have been recast in accordance with ASC Topic 805, Business Combinations. See Note 2.

The preparation of the Partnership’s consolidated financial statements in accordance with accounting principles generally accepted in the United States (GAAP) require management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

The Partnership accounts for their regulated operations in accordance with applicable regulatory accounting guidance under Accounting Standards Codification (ASC) Topic 980 – Regulated Operations. The economic effects of regulation can result in a regulated partnership recording assets for costs that have been or are expected to be approved for recovery from customers in a future period or recording liabilities for amounts that are expected to be returned to customers in the rate-making process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, the Partnership records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. The Partnership cannot be removed from an operational capacity without prior approval from the PUCT.

Regulatory assets and liabilities are amortized consistent with the treatment of the related cost in the ratemaking process. Management assesses whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential legislation. Additionally, management assesses whether any regulatory liabilities have been incurred. Management believes the existing regulatory assets are probable of recovery and that no other regulatory liabilities, other than those recorded, have been incurred. These regulatory assets and liabilities are primarily classified in the Consolidated Balance Sheets as deferred charges – regulated assets, net and regulatory liabilities, respectively.

The PUCT has designated certain tariffs such as Transmission Cost Recovery Factor (TCRF) and Energy Efficiency Cost Recovery Factor (EECRF) as reconcilable, which means the differences between amounts billed under these tariffs and the related incurred costs are, deferred as either a regulatory asset or liability. Accordingly, at prescribed intervals, future tariffs are adjusted to repay regulatory liabilities or collect the regulatory assets.

The Partnership’s subsidiaries CVPE and GSPE recognize allowance for funds used during construction (AFUDC) as a cost during the construction of transmission plant. AFUDC is a regulatory cost accounting procedure where both interest charges on borrowed funds and a return on equity used to finance construction are included in the recorded costs of transmission plant while being constructed. The equity portion of capitalized AFUDC is accounted for as other income.

The Partnership considers all short-term, highly liquid investments with original maturities of three months or less to be cash equivalents.

Inventory primarily consists of transmission parts and materials used in the construction of property, plant and equipment. Inventory is valued at average cost when it is acquired and used.

Property, plant and equipment is stated at the original cost of acquisition or construction, which may include the cost of contracted services, direct labor, materials, acquisition adjustments, capitalized interest and overhead items. The Partnership leases most of its transmission and distribution assets from SDTS. See Note 2.

In accordance with the FERC uniform system of account, CVPE and GSPE, recognize, as a cost to construction work in progress (CWIP), AFUDC on borrowed funds classified as a reduction of interest expense – net and AFUDC on equity classified as other income – net on the Consolidated Statement of Operations.

The AFUDC blended rate utilized was 6.7% and 6.6% during the years ended December 31, 2016 and 2015, respectively.

When property is retired, the cost of such property, less salvage, is removed from property, plant and equipment and charged to accumulated depreciation.

Maintenance and repairs are charged to expense. Betterments and improvements of assets subject to leases are billed to the lessor and reimbursed in accordance with the lease agreements. Betterments and improvements not subject to leases are capitalized. See Note 3 for more information.

As a result of the settlement of the Partnership’s 2013 rate case approved by the PUCT under Docket No. 41474, effective May 1, 2014, provision for depreciation on property plant and equipment is computed using composite straight-line rates as follows:

The Partnership evaluates impairment of its long-lived assets (including regulatory assets) and certain intangible assets annually or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss shall be recognized only if the carrying amount of a long-lived asset is not recoverable through the expected future cash flows. Regulatory assets are charged to expense in the period in which they are no longer probable of future recovery.

Goodwill represents the excess of costs of an acquired business over the fair value of the assets acquired, less liabilities assumed. Goodwill is not amortized and it is tested for impairment annually or more frequently if events or changes in circumstances arise. As of December 31, 2016 and 2015, approximately $1.1 million of goodwill was recorded in the Partnership’s Consolidated Balance Sheets.

The Partnership accounts for its investment in SDTS using the cost method. The Partnership has no value assigned to this investment. At this time, the Partnership has the right of distribution only after the majority owner receives its required return.

The Partnership records no federal income taxes since these taxes are the responsibility of individual partners. The Partnership is subject to the gross margin tax enacted by the State of Texas. The Partnership recorded a margin tax expense of approximately $1.5 million and $1.3 million as of December 31, 2016 and 2015, respectively. The Partnership has no deferred tax assets or liabilities as of December 31, 2016 or 2015.

The Partnership records revenue based on amounts billed to customers and unbilled amounts based upon an estimate of the revenues to be received for service delivered from the latest billing through the end of the period.

Accounts receivable consist primarily of trade receivables from REPs. In the normal course of business, credit is extended to customers on a short-term basis. Under a PUCT rule relating to the certification of REPs, write-offs of uncollectible amounts owed by REPs are deferred as regulatory assets. The Partnership did not recognize any amounts associated with bad debt expense during the years ended December 31, 2016 and 2015. As of December 31, 2016 and 2015, the allowance for doubtful accounts associated with the Partnership’s customers prior to the move to competition was approximately $601,000 and $602,000, respectively.

Unbilled accounts receivable is comprised of estimated amounts of energy and services delivered from the latest billing through the end of the period. Unbilled revenue of approximately $5.6 million and $5.0 million is included in accounts receivable as of December 31, 2016 and 2015, respectively.

ASC Topic 820, Fair Value Measurements and Disclosures, defines fair value, establishes a framework for measuring fair value in accordance with accounting principles generally accepted in the United States, and expands disclosures about fair value measurements. The Partnership follows ASC 820 in its valuation of its marketable securities. ASC 820 defines fair value as the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC 820 classifies the levels used to measure fair value into the following hierarchy:

Level 1 – Quoted prices in active markets for identical assets and liabilities.

Level 2 – Valuations based on one or more quoted prices in markets that are not active; quoted prices for similar assets or liabilities in active markets; inputs that are observable other than quoted prices for the asset or the liability; or inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3 – Valuations based on inputs that are unobservable and significant to the overall fair value measurement.

The Partnership’s interest expense – net, primarily consists of interest expense from failed sale-leaseback, credit facility and senior secured notes, see Note 4, Failed Sale-Leaseback – Financing Obligation, Note 10, Credit Facility and Note 11, Long-Term Debt. AFUDC on borrowed funds of $3.0 million and $2.5 million was recognized as a reduction of the Partnership’s interest expense during the years ended December 31, 2016 and 2015, respectively.

AFUDC on other funds of $2.9 million and $4.6 million was recognized in other income – net, during the years ended December 31, 2016 and 2015, respectively.

Comprehensive income includes net income and other comprehensive income, which consists of unrealized gains and losses on derivative financial instruments. The Partnership records deferred hedge gains and losses on its derivative financial instruments that qualify as cash flow hedging instruments as other comprehensive income.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Clarification of Certain Cash Receipts and Cash Payments. The objective of ASU 2016-15 is to eliminate the diversity in practice related to the classification of certain cash receipts and payments in the statement of cash flows, by adding or clarifying guidance on eight specific cash flow issues. ASU 2016-15 is effective for periods beginning after December 15, 2017 with early adoption permitted. The new standard requires a modified retrospective transition approach for all periods presented, unless deemed impracticable, in which case, prospective application is permitted. The Partnership is currently evaluating the new guidance and has not determined the impact this standard may have on our cash flows.

In February 2016, the FASB issued ASU 2016-02, Leases. ASU 2016-02 amended the existing accounting standard for lease accounting, including requiring lessees to recognize most leases on their balance sheets and making targeted changes to lessor accounting. ASU 2016-02 is effective for periods beginning after December 15, 2019 with early adoption permitted. The new standard requires a modified retrospective transition approach for all leases existing at, or entered into after, the date of initial application, with an option to use certain transition relief. The Partnership is currently evaluating the new guidance and has not determined the impact this standard may have on its financial position, results of operations or cash flows.

In April 2015, the Financial Accounting Standards Board (FASB) issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30), Simplifying the Presentation of Debt Issuance Costs. ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with debt discounts. ASU 2015-03 was effective for periods beginning after December 15, 2015 with early adoption permitted. The adoption of the new guidance was applied on a retrospective basis with each balance sheet presented reflecting the new guidance along with transitional disclosures. The adoption did change the presentation of our financial position. As a result, $748,000 of deferred financing costs were reclassed from deferred charges – regulatory assets - net to long-term financing obligation, less unamortized deferred financing costs on the Partnership’s Consolidated Balance Sheets as of December 31, 2015. The adoption of the new guidance did not have an impact on the Partnership’s consolidated results of operations or cash flows.

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. ASU 2014-15 defines management’s responsibility to evaluate whether there is a substantial doubt about an organization’s ability to continue as a going concern and to provide related disclosures in the notes to financial statements. ASU 2014-15 was effective for annual periods ending after December 15, 2016 with early adoption permitted. The standard requires that management should evaluate if there are conditions or events, considered in the aggregate, that raise substantial doubt about the organizations ability to continue as a going concern within one year after the date the financials are issued. The Partnership adopted ASU 2014-15 for the period ended December 31, 2016. The adoption of ASU 2014-15 did not have an impact on the Partnership’s consolidated financial statements.

In May 2014, the FASB issue ASU 2014-09, Revenue from Contracts with Customers. ASU 2014-09 requires revenue to be recognized when promised goods or services are transferred to customers in an amount that reflects the expected consideration for theses goods and services. The guidance supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. ASU 2014-09 is effective for periods beginning after December 15, 2017. The Partnership is currently evaluating the new guidance and has not determined the impact this standard may have on the its financial position, results of operations or cash flows.

On March 18, 2016, Hunt Power, L.P. (HP), an affiliate of the Partnership, contributed all of its ownership interest in GS Project Entity, L.L.C. (GSPE) to the Partners. The Partners contributed their interests in GSPE to the Partnership. GSPE became a wholly owned subsidiary of the Partnership. The Partnership accounted for the contributions of GSPE as common control transactions whereby the net assets acquired are combined with the Partnership at their carrying value. As a result of this common control transaction, net income of $647,000 was included in the Partnership’s Consolidated Statement of Operations for the year ended December 31, 2015. GSPE was formed on January 6, 2015 for the purpose of financing and owning the Golden Spread 345 kV-Transmission Line Project (GS Project). The Partnership’s financial statements have been adjusted to reflect GSPE’s activities from the formation date. The approximately 55 circuit miles transmission line connects Golden Spread Electric Co-op (GSEC) gas-fired generation facilities to the White River Station in the Texas Panhandle which is owned by SDTS.

On May 6, 2016, HP also contributed all of its ownership interest in CV Project Entity, L.L.C. (CVPE) to the Partners. The Partners contributed their interests in CVPE to the Partnership. CVPE became a wholly owned subsidiary of the Partnership. The Partnership accounted for the contributions of CVPE as common control transactions whereby the net assets acquired are combined with the Partnership at their carrying value. As a result of this common control transaction, net income of $2.2 million was included in the Partnership’s Consolidated Statement of Operations for the year ended December 31, 2015. CVPE was formed on November 14, 2014 for the purpose of financing and owning the Cross Valley 345 kV-Transmission Line Project (CV Project). The approximately 48 circuit miles transmission line connects the eastern half of the North Edinburg substation owned by American Electric Power (AEP) to the Palmito Station in the Texas Panhandle which is owned by SDTS. The Partnership’s financial statements have been adjusted to reflect CVPE’s activities from the formation date. The CV Project was acquired by CVPE on January 15, 2015.

The Partnership leases most of its Transmission and all of its Distribution (T&D) assets from SDTS, a related party, under five Master Lease Agreements (MLA). See Note 16, Regulatory Proceedings. Also under these same MLAs, SDTS is responsible for funding all prudently incurred electric plant capital expenditures deemed necessary to serve customers by the Partnership. In accordance with the MLAs, the Partnership is responsible for the maintenance and the operation of the T&D assets and for the compliance with all regulatory requirements of the PUCT, the FERC, and any other regulatory entity with jurisdiction over the T&D assets. The MLAs obligate the Partnership to pay all property-related expenses, including maintenance, repairs, taxes on equipment in service, insurance, and to comply with the terms of the secured credit facilities and secured-term loan, if any, affecting the leased assets. The MLAs are subject to failed sale-leaseback accounting. See Note 4.

The MLAs, as amended, expire at various dates from December 31, 2017 through December 31, 2022. Each agreement includes annual base payments while all but one agreement includes additional payments, based on an agreed upon percentage of revenue earned by the Partnership, as defined in the MLAs, in excess of annual specified breakpoints. The rate used to calculate additional payments varies by lease and ranges from a high of 37% to a low of 23% over the term of the agreements.

The Partnership made fixed lease payments during the periods presented as follows:

The Partnership’s MLAs include a rent validation after year end to true up lease payments for the difference between actual and estimated incremental capital expenditures placed in service. As a result of the rent validation, the Partnership will make additional fixed payments of approximately $313,000 in March 2017 associated with the year ended December 31, 2016. The Partnership made additional fixed payments of approximately $858,000 on April 12, 2016 associated with the year ended December 31, 2015.

The Partnership is also subject to certain restrictive covenants, including indebtedness limits, contained in the MLAs. The Partnership was in compliance with all such covenants as of December 31, 2016 and 2015.

The Partnership leases most of its T&D assets from SDTS, a related party. SDTS has legal title to such T&D assets under lease. The Partnership, as a managing member of SDTS, has the exclusive power and authority on behalf of SDTS to manage, control, administer, and operate the T&D assets and business affairs of SDTS in accordance with the limited liability company agreement governing SDTS. These rights and obligations constitute continuing involvement, which results in failed sale-leaseback (financing) accounting. Under failed sale-leaseback accounting, the Partnership is deemed owner of the assets under all MLAs, including assets currently under construction. Consequently, the T&D assets, including assets currently under construction and corresponding financial obligations are included in the Partnership’s Consolidated Balance Sheets. The leases are considered a failed sale-leaseback (financing) due to the Partnership’s continuing involvement in SDTS and due to the ongoing involvement in the construction of the T&D assets as defined by ASC Topic 840, Accounting for Leases.

Approximately $1.6 billion and $1.4 billion are included in long-term financing obligation liabilities related to the failed sale-leaseback (financing), as of December 31, 2016 and 2015, respectively. Approximately $39.0 million and $32.0 million of the failed sale-leaseback (financing) obligation are included in current liabilities as of December 31, 2016 and 2015, respectively.

The Partnership recorded interest on failed sale-leaseback (financing) in interest expense, net as follows:

As a result of the failed sale-leaseback (financing) transaction, the Partnership accounted for lease payments to the lessor as a reduction of its financing obligation. Payments made on the long-term financing obligation were as follows:

Future payments of the financing obligation as of December 31, 2016 are as follows:

The Partnership recorded depreciation expense related to the assets accounted for in accordance with failed sale-leaseback as follows:

The major classes of property, plant and equipment at December 31, 2016 and 2015 are as follows:

	December 31,
(In thousands)	2016			2015
Property, plant and equipment
Leased system	$	1,724,090		$	1,484,792
Transmission plant		262,279			—
General plant		33,878			31,485
		2,020,247			1,516,277
Construction Work in Progress:
Leased system under construction		103,695			117,064
Transmission plant under contruction		—			223,017
General plant under construction		1,568			1,182
		105,263			341,263
Other		293			293
Total Property, plant and equipment		2,125,803			1,857,833
Accumulated Depreciation - Leased system		(257,548	)		(225,880	)
Accumulated Depreciation - Transmission plant		(2,021	)		—
Accumulated Depreciation - General plant		(18,488	)		(16,122	)
Property, Plant, and Equipment - net	$	1,847,746		$	1,615,831

General plant consists of a warehouse, furniture, fixtures, equipment, computer hardware, software, and vehicles.

Regulatory assets represent probable future recovery of costs from customers through the regulatory ratemaking process. The table below provides detail of deferred charges that are included on the Partnership’s Consolidated Balance Sheets as of December 31, 2016 and 2015.

Net deferred costs recoverable in future years as of December 31, 2016 and 2015 are as follows:

		December 31, 2016							December 31, 2015
	Amortization	Gross					Net		Gross					Net
	Period	Carrying		Accumulated			Carrying		Carrying		Accumulated			Carrying
(In thousands)	Ends	Amount		Amortization			Amount		Amount		Amortization			Amount
Deferred costs recoverable in future years
Deferred financing costs	(a)	$	5,767	$	(2,298	)	$	3,469	$	5,763	$	(1,092	)	$	4,671
Inception operating costs	(a)		23,793		—			23,793		23,793		—			23,793
Rate case costs	(b)		10,461		(4,263	)		6,198		5,471		(2,210	)		3,261
Transmission cost recovery factor	(c)		2,603		—			2,603		—		—			—
Study costs	(d)		3,629		(1,619	)		2,010		3,628		(994	)		2,634
Transition to competition	(e)		2,289		(320	)		1,969		1,963		(200	)		1,763
Advanced metering costs	(f)		1,755		—			1,755		1,636		—			1,636
Energy efficiency cost recovery factor	(g)		10		—			10		—		—			—
Net Deferred Charges - Regulatory Assets		$	50,307	$	(8,500	)	$	41,807	$	42,254	$	(4,496	)	$	37,758

Deferred financing costs included in net deferred charges – regulatory assets consist of debt issuance costs incurred in connection with the construction credit agreements associated with GSPE and CVPE. These assets are classified as regulatory assets and amortized over the length of the related loan. These costs will be included in the costs to be recovered in connection with a future rate case.

The Partnership filed a rate case with the PUCT under Docket No. 41474 (2013 rate case) to adjust the retail delivery tariff for the Stanton, Brady, and Celeste customers. The application was based on a test year ended December 31, 2012, with an effective date of May 1, 2014. The final order was issued January 23, 2014. The final order of the 2013 rate case addressed recovery for costs associated with the transition to competition and certain study costs. Recovery of those costs began when the new tariff went into effect on May 1, 2014. In addition to those costs, the recovery of the 2013 rate case expenses was proposed under a separate docket – PUCT Docket No. 41723.

The 2013 rate case order required the Partnership to file a rate case on or before July 1, 2016. In Docket No. 45414, the PUCT ordered the Partnership to file a Rate Filing Package (RFP) by April 30, 2016. The Partnership filed the RFP to adjust the retail delivery tariff for all customers under Docket No. 45414 on April 29, 2016 (April Filing). The application was based on the test year ended December 31, 2015. All rate case costs incurred for Docket No. 45414 are included in the regulatory assets.

On October 10,^,2016, the PUCT issued its preliminary order in the April Filing. The preliminary order required the Partnership and SDTS to amend the current application to include separate RFPs for the Partnership and SDTS. Also, the preliminary order required the Partnership and SDTS to make its amended filing no later than January 1, 2017. On December 30, 2016, the Partnership and SDTS filed an amended application with separate RFPs (December Filing) based on the same test year as the April Filing.

The inception operating costs of approximately $23.8 million at December 31, 2016 and 2015 represent operating costs incurred from inception through December 31, 2007. The 2013 rate case settlement established that the Partnership may seek recovery in a future rate case, pursuant to the mechanism established in Docket Nos. 21591 and 27556, of the inception operating costs plus related return on rate base. The right to benefit from the inception operating costs was transferred to SDTS. Consequently, due to the failed sale-leaseback accounting treatment, the Partnership has recorded a corresponding liability in financing obligation.

Regulatory liabilities represent probable future refunds associated with the over-recovery of costs from customers through the regulatory ratemaking process.

The carrying amount of the regulatory liabilities as of December 31, 2016 and 2015 are as follows:

	Amortization
	period	December 31,
(In thousands)	Ends	2016		2015
Postretirement benefits costs	(a)	$	3,018	$	3,051
Postretirement benefits collections	(b)		2,681		1,255
Estimated net removal costs	(c)		1,208		—
Energy efficiency cost recovery factor	(d)		—		591
Transmission cost recovery factor	(e)		—		1,043
Regulatory liabilities		$	6,907	$	5,940

The Partnership made payments associated with the lease of some of its T&D assets to SDTS of approximately $174.6 million and $154.3 million during the years ended December 31, 2016 and 2015, respectively.

The Partnership received payments throughout the period related to the acquisition of gross property plant and equipment, contracted services, direct labor, materials and supervision associated with its existing asset build out on the T&D assets from SDTS of approximately $231.7 million and $243.2 million during the years ended December 31, 2016 and 2015, respectively. These costs are included on the Consolidated Balance Sheets under property, plant and equipment - net as leased system.

On February 12, 2015, the Partnership received a subordinated and unsecured loan agreement of $10.0 million from Loyal Trust No. 1 (LT1), a related party, as amended on, February 16, 2017. The promissory note matures on December 31, 2018. The revolving promissory note accrues interest at the floating JP Morgan Chase Prime Rate with all interest compounded semiannually. The note accrues interest at the greater of the three month London Inter-Bank Offered Rate (LIBOR) plus one hundred fifteen basis points as adjusted or at the floating JP Morgan Chase Prime Rate with all interest compounded semiannually. As of December 31, 2016 and 2015, the Partnership had no amount outstanding on the subordinated note. The interest expense and fees on the subordinated note were approximately $37,000 and $193,000 during the years ended December 31, 2016 and 2015, respectively.

The Partnership leases office space for its Dallas location from an affiliate at a contractually agreed upon lease agreement. Charges for the lease are included in general and administrative expense in the accompanying Consolidated Statements of Operations amounted to approximately $343,000 and $273,000 during the years ended December 31, 2016 and 2015, respectively.

An affiliate of the Partnership provides services to the Partnership at contractually agreed upon rates per hour and set amounts for infrastructure support. Charges for such services included in general and administrative expense in the accompanying Consolidated Statements of Operations amounted to approximately $3.5 million and $4.1 million during the years ended December 31, 2016 and 2015, respectively. Accrued fees included in due to affiliates on the Partnership’s Consolidated Balance Sheets related to these charges were approximately $1.4 million and $1.0 million as of December 31, 2016 and 2015, respectively.

Revenues, income, gains, losses, expenditures, deductions, credits and distributions, as defined in the partnership agreement, are allocated 1 percent to the general partner and 99 percent to the limited partner.

On May 15, 2014, the Partnership entered into an unsecured revolving credit facility of $5.0 million with Amegy Bank, as amended on, December 10, 2014. The credit facility accrues interest on the outstanding balance at the Prime Rate. At December 31, 2016, the Prime Rate was at 3.75%. In addition to the interest on the outstanding balance, commitment fees accrue at 0.35% for the unused portion of the credit facility. The revolving credit facility expires on May 15, 2017. The Partnership has entered into discussions with Amegy Bank in order to extend the maturity of this facility.

As of December 31, 2016 and 2015, the Partnership had no amount outstanding on the revolving credit facility. The interest expense and fees for the revolving credit facility were approximately $115,000 and $112,000 during the years ended December 31, 2016 and 2015, respectively.

The agreement requires maintenance of certain financial ratios and imposes certain restricted covenants. The Partnership was in compliance with all covenants as of December 31, 2016 and 2015, respectively.

(In thousands)	December 31, 2016					December 31, 2015
CVPE
Fixed Rate Notes - $23.5 million	$	23,500	3.58	%		$	23,500	3.58	%
Term Loan - $82.5 million		81,984	2.36	%	*		—	—
Construction term-loan - $106.5 million		—	—				84,000	1.98	%	*
GSPE
Term Loan - $57.2 million		56,843	2.36	%	*		—	—
Construction term-loan - $84.0 million		—	—				59,200	1.98	%	*
Total long-term debt		162,327					166,700
Less: current portion of long-term debt		3,493					—
Long-term debt	$	158,834				$	166,700

Senior Secured Credit Facilities – On January 15, 2015, in conjunction with the acquisition, CVPE entered into a construction-term loan agreement consisting of $106.5 million construction term loan syndicated to five banks and a $23.5 million senior secured note issued to Prudential Insurance Company of America and affiliates (Fixed Rate Notes). The senior secured credit facilities and Fixed Rate Notes are collateralized by the CV Project.

The $106.5 million construction-term loan accrued interest at LIBOR plus 1.75% and matures on January 15, 2020. LIBOR resets at each selected interest period (one, three, or six months), at CVPE’s discretion at the current market rate. Interest was payable the last day of the selected interest period for interest periods of three months or less, and every three months for interest periods greater than three months.

The CV Project was placed in service in June 10, 2016 and the new transmission cost of service (TCOS) rate that was determined based on a rate base that included the CV Project was approved on September 22, 2016 by the PUCT. On November 30, 2016, the amount outstanding on the construction-term loan was converted into a term loan with a balance of $82.5 million. After this conversion, interest accrues at LIBOR plus 1.75%. Interest is payable the last day of the selected interest period for interest periods of three months or less, and every three months for interest periods greater than three months. Amortized principal amounts of the term loan are payable quarterly after the conversion. As of December 31, 2015, CVPE had $1.3 million letter of credit outstanding that was cancelled on May 25, 2016. The outstanding borrowing under the term loan at December 31, 2016 was $82.0 million. The outstanding borrowing under the construction-term loan at December 31, 2015 was $84.0 million.

As of December 31, 2016 and 2015, the Fixed Rate Notes had a principal balance of $23.5 million. Interest is payable quarterly at a rate of 3.58% per annum. The Fixed Rate Notes mature on January 15, 2020 and do not provide for any principal payments.

The construction-term loan agreement and senior secured notes contain certain default triggers, including without limitation: failure to maintain compliance with financial and other covenants contained in the agreement, limitation on liens, investments and the incurrence of additional indebtedness. CVPE was in compliance with all debt covenants for the construction-term loan agreement at December 31, 2016 and 2015.

On March 31, 2015, GSPE entered into a construction-term loan agreement of $84.0 million syndicated to three banks. The senior secured credit facilities are collateralized by GSPE’s assets. The $84.0 million construction-term loan accrued interest at LIBOR plus 1.75%. LIBOR resets at each selected interest period (one, two, three or six months), at GSPE’s discretion, at the current market rate. Interest was payable the last day of the selected interest period for interest periods of three months or less, and every three months for interest periods greater than three months.

The GS Project was placed in service in March 29, 2016 and the new TCOS rate that was determined based on a rate base that included the GS Project was approved on June 13, 2016 by the PUCT. On October 31, 2016, the amount outstanding on the construction-term loan was converted into a term loan with a balance of $57.2 million. After this conversion, interest accrues at LIBOR plus 1.75%. Interest is payable the last day of the selected interest period for interest periods of three months or less, and every three months for interest periods greater than three months. Amortized principal amounts of the term loan are payable quarterly after the conversion. The term loan will mature on the third anniversary after principal conversion. As of December 31, 2015, GSPE had $2.8 million letters of credit outstanding that expired on March 30, 2016. The outstanding borrowing under the term loan at December 31, 2016 was $56.8 million. The outstanding borrowing under the construction-term loan at December 31, 2015 was $59.2 million.

The construction-term loan agreement contains certain default triggers, including without limitation: failure to maintain compliance with financial and other covenants contained in the agreement, limitation on liens, investments and the incurrence of additional indebtedness. GSPE was in compliance with all debt covenants for the construction-term loan agreement at December 31, 2016 and 2015.

Future maturities of the total long-term debt as of December 31, 2016 are as follows:

Interest – On March 31, 2015, CVPE entered into an interest rate swap agreement that has been designated as a cash flow hedge against variable interest with Wells Fargo, a lender in the credit facility, serving as counterparty, whereby CVPE received variable (1 month LIBOR), the qualifying benchmark rate and paid a fixed rate of 0.7185% per annum, thereby converting a portion of the construction-term loan to a fixed rate. Notional amounts reset on a monthly basis and did not exceed $35.4 million at any given time. There were no notional amounts as of December 31, 2016 as this swap agreement terminated on that date. Notional amounts were $27.1 million as of December 31, 2015.

On June 15, 2015, GSPE entered into an interest rate swap agreement that has been designated as a cash flow hedge against variable interest with DNB Capital LLC, a lender in the senior secured credit facilities, serving as counterparty, whereby GSPE received variable (1 month LIBOR), the qualifying benchmark rate and paid a fixed rate at 0.760% per annum, thereby converting a portion of the construction-term loan to a fixed rate. Notional amounts reset on a monthly basis and did not exceed $38.1 million at any given time. There were no notional amounts as of December 31, 2016 as this swap agreement terminated on that date. Notional amounts were $32.9 million as of December 31, 2015.

The cash flow hedging instrument was recorded as a liability, with an offset to accumulated other comprehensive income to the extent the cash flow hedging instrument was effective. The cash flow hedging instrument gains and losses included in other comprehensive income were reclassified into earnings as the underlying transaction occurred. There was no cash flow hedging instrument ineffectiveness recorded during the years ended December 31, 2016 and 2015.

The fair value of derivative liabilities relating to interest rate swaps are as follows:

The Partnership reclassified approximately $32,000 included in other comprehensive income, during each of the years ended December 31, 2016 and 2015 to interest expense, net on the Consolidated Statement of Operations. As of December 31, 2016, there was no unrealized derivative fair value losses related to the cash flow hedges that were recorded in accumulated other comprehensive loss in the Partnership’s Consolidated Statements of Partners’ Capital.

All Transmission Service Providers (TSPs) within Electric Reliability Council of Texas (ERCOT) provide open access transmission service and the costs are ultimately passed through to end-use customers. The PUCT regulates the transmission rates that are charged by the ERCOT TSPs. The Partnership is billed based on the Partnership’s pro rata share, during the prior year, of the average of ERCOT coincident peak demand for the months of June, July, August, and September (ERCOT 4CP), excluding the portion of coincident peak demand attributable to wholesale storage load. Each TSP files a tariff for transmission service to establish its rates, calculated as the TSP’s commission-approved transmission cost of service, or revenue requirement, divided by the aggregate ERCOT 4CP during the prior year. Therefore, the monthly transmission service charge to be paid by the Partnership is the product of each TSP’s monthly rate as specified in its tariff and the Partnership’s previous year’s share of the aggregate ERCOT 4CP.

Taking power over the ERCOT network requires the Partnership to pay fees regulated by the PUCT. The annual charges to use the ERCOT transmission network cover the period from January 1 through December 31 of each year. Because the use of the network is governed by ERCOT and falls under the jurisdiction of the PUCT, a contract is not required with each ERCOT TSP.

The Partnership provides continued major medical and dental coverage to retired employees and their dependents meeting certain eligibility requirements. The Partnership’s cost to maintain such benefits during the years ended December 31, 2016 and 2015 totaled approximately $245,000 and $785,000, respectively. The cost is included in general and administrative expense in the Consolidated Statements of Operations. Retiree contributions to the plan totaled approximately $149,000 and $197,000 during the years ended December 31, 2016 and 2015, respectively.

The Partnership’s postretirement health care benefit plan provides prescription drug coverage. The Medicare Prescription Drug Improvement and Modernization Act of 2003 includes a federal subsidy for plans that offer prescription drug benefits that are actuarially equivalent to Medicare Part D. The Partnership and the actuarial advisors have determined that the prescription drug coverage provided by the Partnership’s postretirement health care benefit plan is actuarially equivalent to Medicare Part D, and accordingly, the subsidy provides some relief for ongoing retiree prescription costs.

The Partnership is required to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability on its balance sheet. FASB guidance requires an entity to include items that have not yet been recognized as net periodic postretirement benefit cost as a component of accumulated other comprehensive income. However, for a regulated utility this information is allowed to be recorded as a regulatory asset if: (i) the utility has historically recovered and currently recovers postretirement benefit plan expenses in its electric rates; and (ii) there is no negative evidence that the existing regulatory treatment will change. The Partnership has recorded the unrecognized components of net periodic postretirement benefit cost as a regulatory asset (liability) as these expenses are probable of future recovery.

The components of the postretirement benefit obligation regulatory asset (liability) at December 31, 2016 and 2015 are as follows:

In the postretirement benefit obligation regulatory liability at December 31, 2016, there is a $443,000 net loss that is expected to be recognized as a component of net periodic postretirement benefit cost in 2017.

The following sets forth the obligations, fair value of plan assets and funded status of the postretirement health care plan at December 31, 2016 and 2015:

(In thousands	2016			2015
Benefit obligation, beginning of year	$	10,170		$	13,549
Service costs		51			109
Interest costs		405			506
Benefits paid		(454	)		(361	)
Actuarial gain		283			(3,633	)
Plan amendment		(214	)		—
Benefit obligation, end of year		10,241			10,170
Fair value of plan assets		7,060			7,268
Accumulated postretirement benefit obligation	$	3,181		$	2,902

The following sets forth the assumptions used to determine benefit obligations and net periodic benefit cost:

Net benefits paid during the year ended December 31, 2016 and 2015 were approximately $454,000 and $361,000, respectively. The following table provides estimates of future benefit payments, which reflect expected future service, as applicable:

The following table is the Partnership’s summary of the fair value of plan assets held by the trust as of December 31, 2016 and 2015:

	December 31, 2016						December 31, 2015
(In thousands)	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
Cash and money balances	$	917	$	—	$	—	$	1,371	$	—	$	—
Mutual Funds		6,143		—		—		5,865		—		—
	$	7,060	$	—	$	—	$	7,236	$	—	$	—

The plan assets are being held in a trust account that is classified as Level 1 on the fair value hierarchy discussed in Note 1(m). The Partnership has adopted a conservative investment strategy, with the primary objective of capital preservation and modest returns.

The Partnership has a 401(k) profit sharing plan which covers all of its active employees. At its discretion, the Partnership may match the employee’s contribution to the plan. Matching contributions to the plan were $3.2 million and $2.8 million during the years ended December 31, 2016 and 2015, respectively.

In accordance with ASC Topic 820, Fair Value Measurements and Disclosures, the Partnership is required to assess the fair value of its financial instruments and disclose the level of inputs used for that estimate set forth in ASC 820.

The carrying amounts of the Partnership’s cash and cash equivalents, due to and from affiliates, and accounts payable approximate fair value due to the short-term nature of these assets and liabilities.

As of December 31, 2016 and 2015, the Partnership had approximately $138.8 million and $143.2 million, respectively, of borrowings under the construction-term loans which accrued interest under a floating rate structure. Accordingly, the carrying value of such indebtedness approximated the fair value for the amounts outstanding.

The Partnership also had borrowings totaling $23.5 million under senior secured notes with a rate of 3.58% per annum as of December 31, 2016 and 2015. The fair value of these borrowings is estimated using discounted cash flow analysis based on current market rates.

The Partnership’s derivative contracts consist of cash flow hedging instruments which are not traded on a public exchange. The fair values of the cash flow hedging instrument contracts were determined using discounted cash flow techniques. The techniques incorporate Level 2 inputs and quotes from the counterparty to interest swap contract. These market inputs were utilized in a discounted cash flow calculation considering the cash flow hedging instrument term, credit risk, notional amount and discount rate and were classified as Level 2 in the fair value hierarchy.

Financial instruments, measured at fair value as defined by ASC 820, by level within the fair value hierarchy were as follows:

	Carrying		Fair Value
(In thousands)	Value		Level 1		Level 2		Level 3
December 31, 2016
Long-term debt	$	162,327	$	—	$	162,352	$	—
December 31, 2015
Fair value of derivative liabilities	$	32	$	—	$	32	$	—
Long-term debt		166,700		—		166,665		—

The Partnership has various obligations under operating leases pertaining to equipment, facilities and office space. Charges for the operating leases included in general and administrative expense in the accompanying Consolidated Statements of Operations amounted to approximately $712,000 and $366,000 during the years ended December 31, 2016 and 2015, respectively.

The following is a schedule of future minimum lease payments required under operating leases with a term of greater than 12 months at inception as of December 31, 2016:

The Partnership is regulated by the PUCT. The 2013 rate case order required the Partnership to file a rate case on or before July 1, 2016. In Docket No. 45414, the PUCT ordered the Partnership to file an RFP by April 30, 2016. The Partnership filed the RFP to adjust the retail delivery tariff for all customers under Docket No. 45414 on April 29, 2016 (April Filing). The application was based on the test year ended December 31, 2015.

On October 10,^,2016, the PUCT issued its preliminary order in the April Filing. The preliminary order required the Partnership and SDTS to amend the current application to include separate RFPs for the Partnership and SDTS no later than January 1, 2017. On December 30, 2016, the Partnership and SDTS filed an amended application with separate RFPs based on the same test year as the April Filing.

Consistent with the Preliminary Order, SULP and SDTS proposed to replace their five existing MLAs with two new leases, one for transmission assets and one for distribution assets. Each of the leases, if approved by the PUCT, will be executed upon the effectiveness of the rate case and will have a four year term. SULP will continue to have operational control over SDTS’s T&D assets and will remain primarily responsible for regulatory compliance and reporting requirements on behalf of and with cooperation with SDTS.

The outcome of the December Filing is uncertain. Recent events, including complaints but not limited to, from ratepayers in the Partnership’s service territory regarding the delivery rates, have placed the Partnership under heightened scrutiny and may affect the outcome of the rate case. Any such adverse determinations by the PUCT could adversely affect the Partnership’s operating results and financial condition and ability to meet its obligations.

In June 2016, the Partnership began discussions with the staff of the PUCT and the Office of Public Utility Counsel regarding the Partnership’s procedure for transitioning customers from its secondary service less than or equal to 10 kW (Small Secondary) rate schedule to its secondary service greater than 10 kW (Large Secondary) rate schedule. In early July, the Partnership received 13 complaints from customers stating that they had demand meters and were incorrectly moved to the Large Secondary rate schedule. On July 14, 2016, the Partnership received formal notification from the Oversight and Enforcement (O&E) Division of the PUCT that an investigation was being opened to determine whether the Partnership’s policy and procedures related to the transitioning of approximately 1,500 customers from the Small Secondary to the Large Secondary rate schedule were consistent with the Partnership’s tariff for delivery service, the Public Utilities Regulatory Authority (PURA), and the PUCT’s rules. After the O&E staff analyzed the data obtained from the Partnership, O&E staff concluded that over 1,000 customers were impacted by this transition from Small Secondary to the Large Secondary rate schedule. On February 17, 2017, the Partnership and O&E (the Parties) executed and filed in Docket No 46873, resolving O&E staff’s investigation of the Partnership for alleged violations of PURA, the PUCT’s rules, and the Partnership’s tariff. The settlement agreement requires the Partnership to pay an administrative penalty for approximately $425,000 and to refund to impacted customers approximately $990,000 including interest. As of December 31, 2016, approximately $1.4 million was accrued as accounts payable and accrued liabilities on the Partnership’s Consolidated Balance Sheet.

On or about January 14, 2002, the Partnership and Southwestern Public Service Company (SPS) entered into a Transmission Agent Agreement (the Contract) for SPS to obtain transmission services from Southwest Power Pool (SPP) for the Partnership. On or about December 31, 2013, the Partnership disconnected from SPP and transitioned its load to ERCOT. On or about July 3, 2014, SPS filed a lawsuit against the Partnership for allegedly breaching the Contract. In the lawsuit, SPS claimed the Partnership owed it approximately $2.9 million in pass-through fees associated with services allegedly provided during the 2014 calendar year. SPS simultaneously filed an action with FERC, asking FERC to waive all the Partnership’s fees incurred after the Partnership moved to ERCOT. The FERC proceeding denied SPS’s request for a waiver of the fees.

The parties settled on December 1, 2016 for approximately $1.5 million. As of December 31, 2015, approximately $1.2 million was accrued for legal proceedings included in commitment and contingencies on the Partnership’s Consolidated Balance Sheet.

Supplemental cash flow information and non-cash investment and financing activities for the years ended December 31 are as follows:

(In thousands)	2016		2015
Supplemental cash flow information
Cash paid for interest	$	143,606	$	126,758
Cash paid for margin taxes		1,315		1,970
Non-cash change in regulatory pension costs		33		3,835
Non-cash investing and financing activities
Non-cash right of way additions to property, plant and equipment		2,721		—
Noncash financing obligation incurred		225,929		183,806
Change in accrued additions to property, plant and equipment		15,045		15,091
Allowance for funds used during contruction - debt		2,989		2,540

On January 24, 2017, the Partnership drew $5.0 million under its revolving credit facility with Amegy Bank. The credit facility accrues interest on the outstanding balance at the Prime Rate at 3.75%. On January 24 and February 13, 2017, the Partnership drew $2.0 million and $8.0 million under its subordinated note with Royal Trust No. 1. The subordinated note accrues interest on the outstanding balance at the floating JP Morgan Chase Prime Rate with all interest compounded semiannually.

The Partnership has evaluated subsequent events from the Balance Sheet date through February 23, 2017, the date at which the Financial Statements were made available to be issued, and determined there are no other items to disclose.

	Years ended December 31,
	2016	2015
Transmission plant	1.29% - 3.14%	1.29% - 2.16%
Distribution plant	1.56% - 4.97%	1.56% - 4.97%
General plant	0.80% - 5.12%	0.80% - 5.12%

(In thousands)	Total
Year Ending December 31:
2017	$	163,057
2018		86,094
2019		84,163
2020		70,552
2021		8,528
Thereafter		4,414
Total future minimum lease payments	$	416,808

	December 31,
(In thousands)	2016		2015
Failed Sale-lease back interest expense
Fixed portion of failed-leaseback interest	$	113,357	$	102,693
Variable portion of failed-leaseback interest		27,116		25,532
Failed Sale-lease back interest expense	$	140,473	$	128,225

(In thousands)	Total
Year Ending December 31:
2017	$	39,028
2018		19,473
2019		14,098
2020		8,839
2021		3,748
Thereafter		1,382,151
Total financing obligation		1,467,337
Less: current portion of financing obligation		(39,028	)
Leased system under construction obligation		103,695
Lease deferral (Note 7)		23,793
Long-term lease obligation	$	1,555,797

(In thousands)	2016			2015
Defined benefit postretirement plan:
Net Gain	$	(3,018	)	$	(3,051	)
Total		(3,018	)		(3,051	)

	Balance Sheet	December 31,
(In thousands)	Location	2016		2015
Fair value of derivative liabilities - current	Current liabilities	$	—	$	32
Fair value of derivative liabilities		$	—	$	32

	2016			2015
Discount rate used for year-end obligation		4.00	%		4.17	%
Discount rate used for net periodic benefit cost		4.17	%		3.88	%
Current medical cost trend rate for year-end obligation		7.50	%		6.50	%
Current medical cost trend rate for net periodic benefit cost		6.50	%		7.00	%
Rate to which the costs trend rate is assumed to decline		5.00	%		5.00	%
Rate of return on assets		3.75	%		3.75	%