hifr-ex991_304.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, 2015 and 2014, and the related consolidated statements of operations, 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 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, 2015 and 2014, 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.

	December 31,
	2015		2014
Assets
Property, Plant and Equipment - net	$	1,608,648	$	1,230,171
Current Assets
Cash and cash equivalents		8,774		7,383
Accounts receivable, net		34,356		32,810
Due from affiliates		34,317		32,292
Prepayments and other current assets		1,713		1,695
Total current assets		79,160		74,180
Goodwill		1,100		1,100
Deferred Charges – Regulatory Assets, net		33,835		38,834
Total Assets	$	1,722,743	$	1,344,285

Partners' Capital and Liabilities
Partners' Capital
General partner	$	3	$	26
Limited partner		5,115		7,413
Total partners' capital		5,118		7,439
Long Term Financing Obligation		1,588,084		1,218,558
Regulatory Liabilities		5,940		3,505
OPEB and Other Liabilities		8,787		9,006
Total Capitalization		1,607,929		1,238,508
Commitments and Contingencies		1,163		—
Current Liabilities
Accounts payable and accrued liabilities		53,015		49,156
Current portion of financing obligation		32,006		32,480
Due to affiliates		27,085		21,999
Current state margin tax payable		1,545		2,142
Total current liabilities		113,651		105,777
Total Partners' Capital and Liabilities	$	1,722,743	$	1,344,285

	Years Ended
	December 31,
	2015			2014
Revenues	$	252,705		$	289,957
Operating Expenses
Purchased power		—			58,462
Distribution expense		28,844			25,970
Transmission expense		25,943			17,805
General and administrative expense		39,384			36,149
Depreciation and amortization		32,099			28,306
Total operating expenses		126,270			166,692

Operating Income		126,435			123,265
Other Expense - net
Interest expense, net		(128,562	)		(107,717	)
Other income	165			404
Tax reimbursements for contributions in aid of construction	973				1,734
Total other expense - net		(127,424	)		(105,579	)
Net (Loss) Income Before Income Taxes		(989	)		17,686
Income Tax Expense		1,332			1,971
Net (Loss) Income	$	(2,321	)	$	15,715

							Total
	General			Limited			Partners' Capital
	Partner			Partner			(Deficit)
Balance at December 31, 2013	$	(131	)	$	(8,145	)	$	(8,276	)
Net Income	157				15,558			15,715
Balance at December 31, 2014	$	26			7,413			7,439
Net Loss		(23	)		(2,298	)		(2,321	)
Balance at December 31, 2015	$	3		$	5,115		$	5,118

	Years Ended
	December 31,
	2015			2014
Cash Flows from Operating Activities
Net (loss) income	$	(2,321	)	$	15,715
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation		29,205			27,689
Amortization of deferred costs		2,894		617
Expensing of prior rate case costs (See note 5)		—		478
Changes in assets and liabilities:
Prepayments and other current assets		(18	)		(587	)
Accounts receivable		(1,546	)		(5,340	)
Due from affiliates		(2,025	)		(1,036	)
Accounts payable, accrued liabilities and other		4,803			1,565
Purchased power payable		—			(8,241	)
Due to affiliates		5,086			10,120
State margin tax payable		(597	)	827
Deferred charges - regulatory assets and liabilities		4,540			(3,910	)
Net cash provided by operating activities		40,021			37,897
Cash Flows from Investing Activities
Additions to general plant		(8,043	)		(4,137	)
Net cash used in investing activities		(8,043	)		(4,137	)
Cash Flows from Financing Activities
Proceeds from short-term borrowing		5,000			—
Proceeds from short-term borrowing from affiliates		10,000			—
Repayments of short-term borrowing		(5,000	)		—
Repayments of short-term borrowing to affiliates		(10,000	)		—
Repayments of financing obligation		(30,587	)		(34,756	)
Net cash used in financing activities		(30,587	)		(34,756	)
Net increase (decrease) in cash and cash equivalents		1,391			(996	)
Cash and cash equivalents at beginning of period		7,383			8,379
Cash and Cash Equivalents at end of period	$	8,774		$	7,383

Supplemental disclosure of cash flow information
Cash paid for interest	$	124,083		$	97,156
Cash paid for margin taxes	$	1,970		$	1,142
Noncash change in regulatory pension costs	$	3,835		$	3,410
Noncash financing obligations incurred	$	399,639		$	177,504

Sharyland Utilities, L.P. (the Partnership or SULP) is a regulated electricity transmission and distribution partnership engaged in providing delivery services to retail electric providers (REPs) serving over 53,000 electric delivery points in 29 counties 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 365 miles in length, through a 300 megawatt (MW) high-voltage direct current transmission interconnection between Texas and Mexico (Railroad DC Tie); and a 300 mile 345 kV transmission loop in the Texas Panhandle and South Plains near Amarillo, Texas.

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., the sole subsidiary of the Partnership was merged with and into SULP as approved by the 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.

The Partnership leases all of its transmission and distribution assets from a related party, Sharyland Distribution & Transmission Services, L.L.C. (SDTS) under a Master Lease Agreements. See Note 2.

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.

Certain reclassifications have been made to prior periods’ consolidated financial statements for comparative purposes. The Partnership changed its presentation in the Consolidated Balance Sheet as of December 31, 2014 by offsetting its transmission cost of service (TCOS) charged from other utilities from accounts payable and accrued liabilities to accounts receivable, net to conform with current presentation.

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 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.

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.

For regulatory purposes the operations of SULP and the assets of SDTS are viewed as one set for regulatory reporting. The Partnership cannot be removed from an operational capacity without prior approval from the PUCT.

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

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 transmission and distribution assets from SDTS. See Note 2.

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 2 for more information.

As a result of the settlement of the Partnership’s 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, 2015 and 2014, 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 $1.3 million and $2.0 million as of December 31, 2015 and 2014, respectively. The Partnership has no deferred tax assets or liabilities as of December 31, 2015 or 2014.

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. The Partnership recognized no amount associated with bad debt expense during the year ended December 31, 2015. Under a PUCT rule relating to the certification of REPs, write-off of uncollectible amounts owed by REPs are deferred as regulatory assets. As of December 31, 2015 and 2014, the allowance for doubtful accounts associated with the Partnership’s customers prior the move to competition was approximately $602,000 and $646,000, respectively. Bad debt expense during the year ended December 31, 2014 was approximately $779,000.

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 $5.0 million and $6.0 million is included in accounts receivable as of December 31, 2015 and 2014, 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.

Prior to May 1, 2014, the day before the move to competition, the Partnership accrued for its purchased power costs based on actual usage for the period. The Partnership’s previous tariffs for electric service included power cost recovery clauses under which electric rates charged to retail customers were adjusted monthly to collect actual purchased power costs incurred in providing service. See Note 9.

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2014-09 (ASU 2014-09), Revenue from Contracts with Customers. ASU 2014-09 is effective for annual reporting periods (including interim reporting periods within those periods) beginning January 1, 2017. Early application is not permitted. Entities have the option of using either a full retrospective or a modified approach to adopt ASU 2014-909. The amendment creates a new ASC Topic 606, Revenue from Contracts with Customers, which supersedes revenue recognition requirements in ASC 605, Revenue Recognition. ASU 2014-09 requires that an entity recognize revenues as performance obligations embedded in sales agreements with customers until they are satisfied by the entity. The Partnership is assessing the effects of the application of the new guidance and has not determined the impact this standard may have on its consolidated financial statements, and the method of adoption.

The Partnership leases all of its Transmission and Distribution (T&D) assets from SDTS, a related party, under Master Lease Agreements (MLA). 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 lease agreements, 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 lease agreements 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 leases are subject to failed sale-leaseback accounting. See Note 3.

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 lease agreements, 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. Fixed payments were approximately $132.3 million and $110.9 million as of December 31, 2015 and 2014, respectively.

The Partnership’s lease agreements 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 $858,000 in March 2016 associated with the year ended December 31, 2015. The Partnership made additional fixed payments of approximately $2.4 million on March 31, 2015 and the Partnership received approximately $2.5 million for over payments of variable payments associated with the year ended December 31, 2014.

The Partnership is also subject to certain restrictive covenants, including indebtedness limits, contained in the lease agreements. The Partnership was in compliance with all covenants as of December 31, 2015 and December 31, 2014.

Future minimum lease payments in accordance with these lease agreements are as follows:

The Partnership leases all of its T&D assets from SDTS, a related party. SDTS has legal title to the T&D assets. 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 master lease agreements, 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 $1.2 billion are included in long-term financing obligation liabilities related to the failed sale-leaseback (financing), as of December 31, 2015 and 2014, respectively. Approximately $32.0 million and $32.5 million of the failed sale-leaseback (financing) obligation are included in current liabilities as of December 31, 2015 and 2014, respectively.

Included in interest expense is interest on the failed sale-leaseback (financing). Interest expense on failed sale-leaseback (financing) was approximately $128.2 million and $107.6 million as of December 31, 2015 and 2014, respectively. The fixed portion of the failed sale-leaseback interest expense was approximately $102.7 million and $78.7 million as of December 31, 2015 and 2014, respectively. The variable portion of the failed sale-leaseback (financing) interest expense was approximately $25.5 million and $28.9 million as of December 31, 2015 and 2014, respectively.

As a result of the failed sale-leaseback (financing) transaction, the Partnership accounts for lease payments to the lessor as a reduction of its financing obligation. Payments on the long-term financing obligation during the years ended December 31, 2015 and 2014 were approximately $30.6 million and $34.8 million, respectively.

Future payments of the financing obligation as of December 31, 2015 are as follows:

The Partnership recorded depreciation expense of approximately $26.8 million and $25.6 million during the years ended December 31, 2015 and 2014, respectively, related to the assets accounted for in accordance with failed sale-leaseback.

The major classes of property, plant and equipment at December 31, 2015 and 2014 are as follows:

(In thousands)	2015			2014
Property, plant and equipment
Leased system	$	1,484,792		$	1,300,411
General plant		31,485			24,756
		1,516,277			1,325,167
Construction Work in Progress:
Leased system under construction		332,898			80,521
Leased system held for future use		—			37,118
General plant		1,182		229
		334,080			117,868
Other	293			79
Total Property, plant and equipment		1,850,650			1,443,114
Accumulated Depreciation - Leased system		(225,880	)		(199,112	)
Accumulated Depreciation - General plant		(16,122	)		(13,831	)
Property, Plant, and Equipment - net	$	1,608,648		$	1,230,171

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 other deferred charges that are included on the Partnership’s Consolidated Balance Sheets as of December 31, 2015 and 2014.

Net deferred costs recoverable in future years as of December 31, 2015 and 2014 are as follows:

	December 31, 2015							December 31, 2014
	Gross					Net		Gross					Net
	Carrying		Accumulated			Carrying		Carrying		Accumulated			Carrying
(In thousands)	Amount		Amortization			Amount		Amount		Amortization			Amount
Deferred financing costs	$	1,069	$	(321	)	$	748	$	1,069		(267	)	$	802
Deferred costs recoverable in future years
Inception operating costs		23,793		—			23,793		23,793		—			23,793
Rate case costs		5,471		(2,210	)		3,261		5,158		(111	)		5,047
Study costs		3,628		(994	)		2,634		3,587		(373	)		3,214
Under-recovered TCRF		—		—			—		3,172		—			3,172
Transition to competition		1,963		(200	)		1,763		1,934		(80	)		1,854
Postretirement benefit costs		—		—			—		784		—			784
Advanced metering costs		1,636		—			1,636		168		—			168
Net Deferred Charges - Regulatory Assets	$	37,560	$	(3,725	)	$	33,835	$	39,665	$	(831	)	$	38,834

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. As a result of the 2013 rate case, the Partnership recognized a write off of approximately $478,000 in regulatory assets during the year ended December 31, 2014.

The inception operating costs of approximately $23.8 million at December 31, 2015 and 2014 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. Consequently, 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. As of December 31, 2015 and 2014, approximately $5.9 million and $3.5 million, respectively, are included in regulatory liabilities on the Consolidated Balance Sheets.

The carrying amount of the regulatory liabilities as of December 31, 2015 and 2014 are as follows:

The Partnership made payments associated with the lease of the T&D assets to SDTS of approximately $154.3 million and $132.0 million during the years ended December 31, 2015 and 2014, 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 $245.9 million and $188.5 million during the years ended December 31, 2015 and 2014, respectively. These costs are included on the Consolidated Balance Sheet under property, plant and equipment - net as leased system.

The Partnership received payments of approximately $8.9 million during the year ended December 31, 2015, for contracted services, direct labor, materials and supervision associated with the Golden Spread interconnection into the 345 kV transmission

loop in the panhandle of Texas from GS Project Entity, LLC. The Partnership did not receive payments during the year ended December 31, 2014 from GS Project Entity, LLC associated with this interconnection. The costs for this project are included on the Partnership’s Consolidated Balance Sheet under Property, Plant and Equipment - net as leased system under construction.

The Partnership received payments of approximately $543,000 during the year ended December 31, 2015 for contracted services, direct labor, materials and supervision associated with the interconnection into the 345 kV transmission line in South Texas near the Mexican border from Cross Valley Project Entity, LLC. The Partnership did not receive payments during the year ended December 31, 2014 from Cross Valley Project Entity, LLC associated with this interconnection. The costs for this project are included on the Partnership’s Consolidated Balance Sheet under Property, Plant and Equipment - net as leased system under construction.

On February 12, 2015, the Partnership received a subordinated and unsecured loan agreement of $10.0 million from Loyal Trust No. 1, a related party, which originally matured on February 12, 2016. The loan agreement was amended and restated on February 15, 2016 with all the terms superseded and established a subordinated revolving promissory note of $10.0 million that matures on December 31, 2016. The revolving promissory note accrues interest at the floating JP Morgan Chase Prime Rate with all interest compounded semiannually. The note accrued 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, 2015, the Partnership had no amount outstanding on the subordinated note. The interest expense and fees on the subordinated note were approximately $193,000 during the year ended December 31, 2015.

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 $4.1 million and $3.0 million during the years ended December 31, 2015 and 2014, respectively. Accrued fees included in due to affiliates on the Partnership’s Consolidated Balance Sheets related to these charges were approximately $1.0 million and $303,000 as of December 31, 2015 and 2014, 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. The credit facility accrues interest on the outstanding balance at the Prime Rate. At December 31, 2014, Prime Rate was at 3.25%. 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.

As of December 31, 2015 and 2014, the partnership had no amount outstanding on the revolving credit facility. The interest expense and fees for the revolving credit facility were approximately $112,000 and $45,000 as of December 31, 2015 and 2014, 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, 2015 and 2014, respectively.

From January 1, 2014 to May 1, 2014, the day before the move to competition, the Partnership purchased all of its electric power pursuant to long-term wholesale electric power contracts with Lower Colorado River Authority (LCRA), and Garland Power and Light (Garland). After the move to competition, the Partnership no longer purchases power for the end use customer. Power is procured by the REPs selected by the end use customer.

The contracts for power covered kWh usage, kW demand levels, transmission, scheduling and ancillary services, and energy and fuel costs. The Partnership’s purchased power costs fluctuated primarily with the price of the fuel and usage. All costs associated with the purchased power were passed through to the end use customer. After the move to competition, revenue does not reflect the cost of purchased power being passed through to the end use customer, therefore the cost of purchase power is not included as a component on the Partnership’s Consolidated Statement of Operations.

The Garland contract and the LCRA contract were terminated on May 31, 2014 upon moving to competition.

After the move to competition and a reconciliation of revenue received with costs incurred related to purchase power, an over-recovery balance of approximately $1.8 million was included in regulatory liabilities in the Partnership’s Balance Sheet as of December 31, 2014.

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, 2015 and 2014 totaled approximately $785,000 and $1.1 million respectively. The cost is included in general and administrative expense in the Consolidated Statements of Operations. Retiree contributions to the plan totaled approximately $197,000 and $264,000 during the years ended December 31, 2015 and 2014, 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. Financial Accounting Standards Board (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, 2015 and 2014 are as follows:

In the postretirement benefit obligation regulatory liability at December 31, 2015, there is a $443,000 net loss that is expected to be recognized as a component of net periodic postretirement benefit cost in 2016.

The following sets forth the obligations, fair value of plan assets and funded status of the postretirement health care plan at December 31, 2015 and 2014:

(In thousands)	2015			2014
Benefit obligation, beginning of year	$	13,549		$	15,815
Service costs		109			143
Interest costs		506			758
Benefits paid		(361	)		(429	)
Actuarial gain		(3,633	)		(2,738	)
Benefit obligation, end of year		10,170			13,549
Fair value of plan assets		7,268			7,596
Accumulated postretirement benefit obligation	$	2,902		$	5,953

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, 2015 and 2014 were approximately $361,000 and $429,000, 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, 2015 and 2014:

	December 31, 2015						December 31, 2014
(In thousands)	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
Cash and money balances	$	1,371	$	—	$	—	$	1,731	$	—	$	—
Mutual Funds		5,897		—		—		5,865		—		—
	$	7,268	$	—	$	—	$	7,596	$	—	$	—

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(l). 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 $2.8 million and $2.5 million during the years ended December 31, 2015 and 2014, respectively.

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 $366,000 and $551,000 during the years ended December 31, 2015 and 2014, 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, 2015:

The Partnership is involved in various legal and regulatory proceedings. While management is unable to predict the outcome of these proceedings, management does not believe that the ultimate resolution will have a materially adverse effect on the Partnership’s results of operation, cash flows or financial position.

As mandated in the final order for the 2013 rate case, the Partnership had agreed to file its next rate case on or before July 1, 2016, however on December 3, 2015, on the PUCT commission open meeting, the Partnership agreed to file its next rate case on or before April 30, 2016.

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 claims the Partnership owes it approximately $2.9 million in pass-through fees associated with 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. In August, the trial court entered an order placing the case on an active docket. Trial has been set for August 29, 2016. SPS filed a motion for summary judgment and the hearing is set for March 4, 2016. The ultimate outcome may vary pending on further discovery.

As of December 31, 2015, accrued amounts for legal proceedings of approximately $1.2 million are included in commitment and contingencies on the Partnership’s Consolidated Balance Sheet.

On January 20, 2016, 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 3.50%. On February 16, 2016, the Partnership drew $4.0 million under its revolving credit facility with Loyal Trust No. 1. The credit facility accrues interest on the outstanding balance at the floating JP Morgan Chase Prime Rate with all interest compounded semiannually.

On January 21, 2016, Shary Holdings, L.L.C., the Partnership’s General Partner, in conjunction with Ovation Acquisition I, L.L.C. and Ovation Acquisition II, L.L.C., submitted a revised proposal for regulatory commitments with the PUCT under the Docket No. 45188, where the parties commit to prepare a proposal for a possible business combination between Oncor Electric Delivery Company, LLC (OEDC) and the Partnership and submit it to the PUCT by June 1, 2016.

The Partnership has evaluated subsequent events from the Balance Sheets date through February 26 2016, the date at which the Financial Statements were made available to be issued, and determined there are no other items to disclose.

Transmission plant		1.29% — 2.16%
Distribution plant		1.56% — 4.97%
General plant		0.80% — 5.12%

(In thousands)	Total
Year Ending December 31:
2016	$	148,751
2017		155,855
2018		81,673
2019		78,923
2020		65,601
Total future minimun lease payments	$	530,803

(In thousands)	Total
Year Ending December 31:
2016	$	32,006
2017		35,817
2018		18,056
2019		13,510
2020		8,376
Thereafter		1,155,634
Total financing obligation		1,263,399
Less current portion of financing obligation		-32,006
Leased system under construction obligation		332,898
Lease deferral (Note 5)		23,793
Long-term lease obligation	$	1,588,084

	2015			2014
Discount rate used for year-end obligation		4.17	%		3.88	%
Discount rate used for net periodic benefit cost		3.88	%		4.93	%
Current medical cost trend rate for year-end obligation		6.50	%		7.00	%
Current medical cost trend rate for net periodic benefit cost		7.00	%		7.50	%
Rate to which the costs trend rate is assumed to decline		5.00	%		5.00	%
Rate of return on assets		3.75	%		3.75	%

(In thousands)	Total
Year Ending December 31:
2016	$	457
2017		464
2018		477
2019		489
2020		490
2021 - 2025		2,579
	$	4,956