hifr-ex991_773.htm

Consolidated Financial Statements
December 31, 2018, and 2017
(With Report of Independent Auditor Thereon)

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, 2018 and 2017, 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 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, 2018 and 2017, 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,
Assets		2018			2017
Current Assets
Cash and cash equivalents	$		27,672	$		25,503
Accounts receivable, net			44,501			55,885
Due from affiliates			8,161			7,096
Inventory			1,844			1,844
Prepayments and other current assets			4,401			3,321
Total current assets			86,579			93,649
Property, Plant and Equipment - net			1,981,685			1,942,393
Goodwill			1,100			1,100
Deferred Charges – Regulatory Assets, net			42,520			44,055
Total Assets	$		2,111,884	$		2,081,197
Liabilities and Partners' Capital
Current Liabilities
Accounts payable and accrued liabilities	$		43,061	$		46,515
Current portion of long-term debt			56,046			3,493
Current portion of financing obligation			34,513			29,611
Due to affiliates			31,926			31,615
State margin tax payable			1,832			1,915
Total current liabilities			167,378			113,149
Long-Term Financing Obligation			1,699,114			1,668,904
Long-Term Debt			99,296			155,342
Regulatory Liabilities			25,977			13,563
OPEB and Other Liabilities			1,148			1,889
Total Liabilities			1,992,913			1,952,847
Commitments and Contingencies
Partners' Capital
General partner			1,139			1,232
Limited partner			117,832			127,118
Total partners' capital			118,971			128,350
Total Liabilities and Partners' Capital	$		2,111,884	$		2,081,197

		Years Ended
		December 31,
		2018				2017
Revenues - net	$		262,507		$		322,375
Operating Expenses
Distribution expense			339				23,735
Transmission expense			17,813				28,898
Administrative and general expense			35,114				40,684
Depreciation and amortization			46,735				42,175
Total operating expenses			100,001				135,492
Operating Income			162,506				186,883
Other Expense - net
Interest expense - net			(170,405	)			(164,675	)
Other income - net			110				708
Tax reimbursements for contribution in aid of construction			-				328
Total other expense - net			(170,295	)			(163,639	)
Net (Loss) Income Before Income Taxes			(7,789	)			23,244
Income Tax Expense			1,580				1,699
Net (Loss) Income	$		(9,369	)	$		21,545

										Total
		General				Limited				Partners'
		Partner				Partner				Capital
Balance at December 31, 2016	$		1,181		$		122,024		$		123,205
Distributions to partners			(164	)			(16,236	)			(16,400	)
Net Income			215				21,330				21,545
Balance at December 31, 2017	$		1,232		$		127,118		$		128,350
Distributions to partners			-				(10	)			(10	)
Net Loss			(93	)			(9,276	)			(9,369	)
Balance at December 31, 2018	$		1,139		$		117,832		$		118,971

		Years Ended
		December 31,
		2018				2017
Cash flows from Operating Activities
Net (loss) income	$		(9,369	)	$		21,545
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation			38,050				40,766
Amortization of deferred costs			9,891				2,615
Allowance for funds used during construction - equity			(58	)			(7	)
Changes in assets and liabilities:
Accounts receivable			11,384				(15,141	)
Due from affiliates			(1,065	)			14,571
Inventory			-				(464	)
Prepayments and other current assets			(1,080	)			561
Deferred charges - regulatory assets and liabilities			3,146				595
Accounts payable, accrued liabilities and other			(2,986	)			(5,399	)
Due to affiliates			311				2,941
State margin tax payable			(83	)			159
Net cash provided by operating activities			48,141				62,742
Cash flows from Investing Activities
Additions to property, plant and equipment			(11,539	)			(3,318	)
Cash proceeds from sale of assets			-				6,891
Net cash (used in) provided by investing activities			(11,539	)			3,573
Cash flows from Financing Activities
Distribution to partners			(10	)			(16,400	)
Proceeds from notes payable			-				997
Proceeds from short-term borrowing			16,000				10,000
Proceeds from short-term borrowing from affiliates			-				10,000
Repayments of notes payable			(299	)			(695	)
Repayments of short-term borrowing			(16,000	)			(10,000	)
Repayments of short-term borrowing to affiliates			-				(10,000	)
Repayments of long-term debt			(3,493	)			(3,492	)
Repayments of financing obligation			(30,631	)			(33,485	)
Net cash used in financing activities			(34,433	)			(53,075	)
Net increase in cash and cash equivalents			2,169				13,240
Cash and cash equivalents at beginning of year			25,503				12,263
Cash and cash equivalents at end of year	$		27,672		$		25,503

Sharyland Utilities, L.P. (the Partnership or SULP) is a partnership engaged in providing transmission of electricity throughout Texas. Those transmission activities include the operation and maintenance of: 138 Kilovolt (kV) looped system of transmission lines and connected substations near Stanton; 138 kV direct current transmission interconnection between Texas and Mexico (Railroad DC Tie); 138 kV transmission lines located in South Texas; 345 kV transmission lines and connected substations in the Texas Panhandle; 345 kV transmission lines near Wichita Falls, Abilene and Brownwood, Texas; and the eastern half of a 345 kV transmission line from the North Edinburg substation to the Palmito substation in South Texas.

The Partnership was organized as a Texas limited partnership on November 3, 1998, as an electric distribution utility located in Hidalgo County, Texas. The Partner’s wholly owned subsidiaries include GS Project Entity, L.L.C. (GSPE), a Texas limited liability company; and CV Project Entity, L.L.C. (CVPE), a Texas limited liability company.

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.

The consolidated financial statements include the Partnership’s account and all other wholly owned entities in which the Partnership has a controlling financial interest. 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 FERC and the Public Utility Counsel of Texas (PUCT) regulating its operations.

The preparation of the Partnership’s consolidated financial statements in accordance with accounting principles generally accepted in the United States (GAAP) requires 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 has a certificate of convenience and necessity (CCN) to operate the regulated assets, and any change to such status would require 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, tariffs were adjusted to repay regulatory liabilities or collect the regulatory assets before November 9, 2017 related to the retail distribution operations, see Note 2 for further discussion of the 2017 Asset Exchange Transaction.

The Partnership and its subsidiaries 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 4.

In accordance with the FERC uniform system of account, the Partnership and its subsidiaries, 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 6.3% and 4.0% during the years ended December 31, 2018 and 2017, 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 4 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, 2018 and 2017, 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 $1.6 million and $1.7 million as of December 31, 2018 and 2017, respectively. The Partnership records no deferred tax assets or liabilities as of December 31, 2018 or 2017 since these taxes are the responsibility of the individual partners.

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 customers. In the normal course of business, credit is extended to customers on a short-term basis. The Partnership did not recognize any amounts associated with bad debt expense during the years ended December 31, 2018 and 2017. No allowance for doubtful accounts associated with the Partnership’s customers was included in the Partnership’s Consolidated Balance Sheet for December 31, 2018 and 2017, 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 $41,000 and $57,000 was recognized as a reduction of the Partnership’s interest expense during the years ended December 31, 2018 and 2017, respectively.

AFUDC on other funds of $58,000 and $7,000 was recognized in other income – net, during the years ended December 31, 2018 and 2017, 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. The new standard should be applied retrospectively to all periods presented, unless deemed impracticable, in which case prospective application is permitted. We adopted the new guidance on January 1, 2018 with no impact on our presentation of our cash flows.

In March 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715), the amendments of ASU No. 2017-07 require an entity to report the service cost component of net benefit costs in the same line item as other compensation costs arising from services rendered by the related employees during the applicable service period. The other components of net benefit cost are required to be presented separately from the service cost component and outside the subtotal of income from operations. Further, ASU No. 2017-07 prescribes that only the service cost component of net benefit costs is eligible for capitalization. The Partnership adopted the new guidance on January 1, 2018 with minimal impact on its financial position, results of operations or 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 the Partnership 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 the extent of the impact this standard may have on its financial position, results of operations or cash flows.

In May 2014, the FASB issued 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 these 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 the Partnership for periods beginning after December 15, 2018. The Partnership’s revenues from customers are tariff-based and are designed to recover the cost of providing electric delivery service to customers including a reasonable rate of return on invested capital. Revenues are generally recognized when the underlying service has been provided in an amount prescribed by the related tariff. The new guidance does not change this pattern of recognition and therefore the adoption will not have an effect on the Partnership’s financial position, results of operations or cash flows.

On October 18, 2018, the Partnership, SU Investment Partners, L.P. (the limited partner of the Partnership), Sempra Texas Utilities Holdings I, LLC (Sempra), and Sempra Energy entered into a definitive agreement (2018 Sale and Asset Exchange Agreement) pursuant to which Sempra will obtain a fifty percent (50%) limited partnership interest in Sharyland Holdings LP (Sharyland Holdings), which will own a 100% interest in the Partnership (the SU Investment). As a condition to Sempra’s investment in Sharyland Holdings, the Partnership also signed a definitive agreement with SDTS and Oncor to exchange, immediately prior to Sempra’s investment in Sharyland Holdings, the GSPE and certain development projects in the Texas Panhandle and South Plains regions, including the Lubbock Power & Light interconnection (LP&L Project) for SDTS’s south Texas assets (the Asset Exchange). The difference between the net book value of the exchanged assets will be paid in cash at closing. After the closing, the Partnership will own and operate all of the assets in South Texas that it currently operates through a Master Lease Agreement with SDTS in addition to the Cross Valley transmission line and associated substations. Additionally, under a separate agreement, Oncor agreed to provide certain operation and maintenance services to the Partnership’s assets following the closing of the transactions. All Master Lease Agreements will be terminated at the close of the transaction with Sempra, Oncor and SDTS. At the close of the 2018 Sale and Asset Exchange transaction, the Partnership will pay off the CV Project and GS Project debt and issue new debt. The Partnership has started the process to refinance the CV Project and GS Project debt discussed in Note 11.

Concurrently with the execution of definitive agreements associated with the SU Investment and the Asset Exchange, Oncor entered into a definitive agreement to acquire InfraREIT, Inc. (the ultimate parent of SDTS)(the Oncor Merger). The Asset Exchange, the SU Investment and Oncor Merger are mutually dependent on one another and neither will become effective without the closing of the other.

The closing of the transactions is dependent upon and subject to several closing conditions, including:

Early termination of the 30-day waiting period required by the HSR Act was received on December 14, 2018. A special meeting of the InfraREIT’s stockholders was held on February 7, 2019, at which time the stockholders voted to approve the transaction.

Under the definitive agreements, the Partnership, SDTS, and Oncor filed a Sale-Transfer-Merger (STM) application Docket No. 48929 with the PUCT on November 30, 2018, and a hearing on the merits is scheduled for April 10-12, 2019. The 180-day deadline for our STM is May 29, 2019, although the PUCT is permitted to extend that deadline for an additional 60 days if necessary.

On July 21, 2017, the Partnership and SDTS signed a definitive agreement (2017 Asset Exchange Agreement) with Oncor Electric Delivery Company LLC (Oncor) to exchange SDTS’s retail distribution assets and the Partnership’s general plant used in distribution operations for a group of Oncor’s transmission assets located in West and Central Texas and cash. The 2017 Asset Exchange Agreement closed in November 2017 and, among other things, resulted in the Partnership exchanging $6.1 million of general plant and regulatory assets used for the retail distribution business net of liabilities at its carrying value with Oncor for approximately $6.1 million in cash. On November 9, 2017 Oncor paid Sharyland $6.9 million based on an estimate, and on February 24, 2018, Sharyland repaid $832,000.

SDTS exchanged approximately $403 million of net distribution assets for $383 million of transmission assets located in West and Central Texas, $18 million of net cash and a $2 million receivable from Oncor as of December 31, 2017.

The Partnership leases these transmission assets from SDTS and operates them under an amended certificate of convenience and necessity (CCN). The Partnership no longer leases the distribution assets transferred to Oncor; however, SDTS continues to own and leases to the Partnership certain substations distribution assets, On October 13, 2017, the PUCT issued an order under Docket No. 47469 approving the Partnership, SDTS and Oncor’s joint Sale-Transfer-Merger application (STM). The Partnership exited the retail distribution business on November 9, 2017.

Concurrently with the execution of the 2017 Asset Exchange Agreement, the Partnership and SDTS entered into an agreement (Rate Case Dismissal Agreement) with certain parties to their pending rate case under Docket No 45414 (Rate Case), which resulted in the dismissal of the Rate Case upon the completion of the 2017 Asset Exchange Agreement with Oncor. On September 29, 2017, the PUCT issued an order dismissing the Rate Case contingent on PUCT approval of the STM and the closing of the 2017 Asset Exchange Agreement. For further information related to the Rate Case and the dismissal, see Note 15, Commitments and Contingencies - regulatory proceedings.

The Partnership leases most of its Transmission and all of its Distribution Substation (T&D) assets from SDTS, a related party, under five Master Lease Agreements (MLA). See Regulatory Proceedings on Note 15, Commitment and Contingencies, leases. 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 compliance with all regulatory requirements of the PUCT, 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, 2019 through December 31, 2022. Each agreement includes annual base payments while all but two agreements include 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 mechanism 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 and variable payments of approximately $1.7 million on February 28, 2019. As a result of the rent validation, the Partnership made additional fixed payments of approximately $346,000 on March 28, 2018, associated with the year ended December 31, 2017.

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, 2018 and 2017.

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 $1.7 billion is included in long-term financing obligation liabilities related to the failed sale-leaseback (financing), as of December 31, 2018 and 2017, respectively. Approximately $34.5 million and $29.6 million of the failed sale-leaseback (financing) obligation are included in current liabilities as of December 31, 2018 and 2017, 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, 2018 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, 2018 and 2017 are as follows:

		December 31,
(In thousands)		2018				2017
Property, plant and equipment
Leased system	$		1,870,466		$		1,757,327
Transmission plant			270,047				262,465
General plant			8,470				10,977
			2,148,983				2,030,769
Construction Work in Progress:
Leased system under construction			62,301				109,697
Transmission plant under construction			4,880				2,231
General plant under construction			773				1,162
			67,954				113,090
Other			293				293
Total Property, plant and equipment			2,217,230				2,144,152
Accumulated Depreciation - Leased system			(225,595	)			(194,142	)
Accumulated Depreciation - Transmission plant			(8,035	)			(4,903	)
Accumulated Depreciation - General plant			(1,915	)			(2,714	)
Property, Plant, and Equipment - net	$		1,981,685		$		1,942,393

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, 2018 and 2017.

			December 31, 2018										December 31, 2017
			Gross							Net			Gross							Net
	Amortization		Carrying			Accumulated				Carrying			Carrying			Accumulated				Carrying
(In thousands)	Period		Amount			Amortization				Amount			Amount			Amortization				Amount
Deferred costs recoverable in future years
Deferred financing costs	(a)	$		5,763	$		(4,710	)	$		1,053	$		5,763	$		(3,504	)	$		2,259
Inception operating costs	(b)			23,793			-				23,793			23,793			-				23,793
Rate case costs	(c)			13,949			(4,998	)			8,951			13,324			(4,998	)			8,326
Study costs/Transition to competition	(d)			5,918			(2,804	)			3,114			5,918			(2,610	)			3,308
Transition cost	(e)			14,100			(8,491	)			5,609			6,369			-				6,369
Net Deferred Charges -Regulatory Assets		$		63,523	$		(21,003	)	$		42,520	$		55,167	$		(11,112	)	$		44,055

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 of debt in connection with a future rate case.

The inception operating costs of approximately $23.8 million at December 31, 2018 and 2017 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.

In 2017, the PUCT approved the 2017 Asset Exchange between the Partnership and Oncor in Docket No. 47649. As part of the Order, the Partnership was allowed to recover certain expenses incurred in connection with the transition of the assets between the Partnership and Oncor (Transition Costs) not to exceed $17.0 million. The actual transition costs to be recovered is $14.1 million to be recovered as a regulatory asset.

See Note 13, Commitments and Contingencies – Regulatory proceedings for information regarding the rate case Docket.

Regulatory liabilities represent probable future reduction in rates due to the over-recovery of costs from customers through the regulatory ratemaking process.

The Partnership’s regulatory liability related to cost of removal is established through depreciation rates and represents the amount that the Partnership expects to incur in the future. The regulatory liability is recorded as long-term liability net of actual removal costs incurred.

With the passage of the Tax Cuts and Jobs Act (TCJA), the PUCT ordered electric utilities in Texas to record a regulatory liability for the balance of excess accumulated deferred income taxes (Excess ADFIT) that now exists because of the decrease in the Federal Income Tax rate from 35% to 21%. The Partnership will continue to assess the amount of the regulatory liability and expects that amortization of the regulatory liability will be determined in the Partnership’s next base rate proceeding to be filed in 2020. The regulatory liability is expected to lower future customer rates over a future period to be determined by the PUCT.

In prior interim transmission rate filings, the Partnership incorrectly included certain distribution property, plant and equipment as part of the Partnership’s transmission rate base resulting in the Partnership over-collecting revenues for certain periods of time. The Partnership has calculated the amount of over collected transmission revenue and an associated carrying charge and has booked an interim TCOS regulatory liability in September 2018. The Partnership expects the regulatory liability to be addressed in its next base rate case to be filed in 2020.

The carrying amount of the regulatory liabilities as of December 31, 2018 and 2017 are as follows:

	Amortization
	period		December 31,
(In thousands)	Ends		2018			2017
Postretirement benefits costs	(a)	$		3,724	$		2,701
Postretirement benefits collections	(b)			5,565			5,765
Estimated net removal costs	(c)			6,444			3,892
Provision in lieu of excess ADFIT	(b)			1,205			1,205
Interim TCOS	(b)			9,039			-
Regulatory liabilities		$		25,977	$		13,563

The Partnership made payments associated with the lease of some of its T&D assets to SDTS as follows:

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 as follows:

Asset build out costs are included on the Consolidated Balance Sheets under Property, Plant and Equipment - net.

On February 12, 2015, the Partnership entered into a subordinated and unsecured loan agreement of $10.0 million with Loyal Trust No. 1 (LT1), a related party, as amended on, February 15, 2019. The promissory note matures on December 31, 2020. The revolving promissory note accrues interest at the floating JP Morgan Chase Prime Rate with all interest compounded semiannually. As of December 31, 2018 and 2017, the Partnership had no amount outstanding on the subordinated note.

No interest expense was incurred on the subordinated note during the year ended December 31, 2018. The interest expense and fees on the subordinated note were approximately $100,000 for the year ended December 31, 2017.

The Partnership leases office space for its Dallas location from an affiliate through a contractually agreed upon lease amount. Charges for the lease are included in general and administrative expense in the accompanying Consolidated Statements of Operations as follows:

An affiliate of the Partnership provides services to the Partnership at contractually agreed upon hourly rates and set amounts for infrastructure support. Charges for such services are included in general and administrative expense in the accompanying Consolidated Statements of Operations as follows:

Accrued fees related to these charges are included in due to affiliates on the Partnership’s Consolidated Balance Sheets and were approximately $1.8 million and $763,000 as of December 31, 2018 and 2017, 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. On August 11, 2017, the credit facility was amended and extended to increase the commitment to $10.0 million and extend the term. On February 18, 2019, the credit facility was extended to expire on August 11, 2020. The credit facility accrues interest on the outstanding balance at the Prime Rate. At December 31, 2018, the Prime Rate was at 5.50%. In addition to the interest on the outstanding balance, commitment fees accrue at 0.35% for the unused portion of the credit facility.

As of December 31, 2018 and 2017, the Partnership had no amount outstanding on the revolving credit facility, respectively. The interest expense and fees for the revolving credit facility were approximately $71,000 and $104,000 during the years ended December 31, 2018 and 2017, 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, 2018 and 2017, respectively.

(In thousands)	Maturity Date		31-Dec-18						December 31, 2017
CVPE
Fixed Rate Notes - $23.5 million	January 15, 2020	$		23,500	3.58	%		$		23,500	3.58	%
Term Loan - $82.5 million	January 15, 2020			77,859	4.09	%	*			79,922	3.32	%	*
GSPE
Term Loan - $57.2 million	October 31, 2019			53,983	4.09	%	*			55,413	3.32	%	*
Total long-term debt				155,342						158,835
Less: current portion of long-term debt				56,046						3,493
Long-term debt		$		99,296				$		155,342

Senior Secured Credit Facilities – On January 15, 2015, CVPE entered into a construction-term loan agreement consisting of a $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 CVPE assets.

The CV Project was placed in service June 10, 2016 and the new transmission cost of service (TCOS) rate that included the CVPE assets 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. The outstanding borrowing under the term loan at December 31, 2018 and 2017 was $77.9 million and $79.9 million, respectively.

As of December 31, 2018 and 2017, the Fixed Rate Notes had a principal balance of $23.5 million, respectively. Interest is payable quarterly at a rate of 3.58% per annum and does not provide for any principal payments. The Fixed Rate Notes and the term loan mature on January 15, 2020. As mentioned in Note 2, the Partnership has also started the process to refinance the outstanding debt and the Partnership believes that it is probable that it will be able to refinance the debt with acceptable terms to the Partnership.

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, 2018 and 2017.

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 GS Project was placed in service in March 29, 2016 and the new TCOS rate that included the GSPE assets 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 October 31, 2019 and the Partnership believes that it is probable that it will be able to refinance the debt with acceptable terms to the Partnership. As mentioned in Note 2, the Partnership has also started the process to refinance the outstanding debt. The outstanding borrowing under the term loan at December 31, 2018 and 2017 was $54.0 million and $55.4 million, respectively.

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, 2018 and 2017.

Future maturities of the total long-term debt as of December 31, 2018 are as follows:

All Transmission Service Providers (TSPs) within the 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 was 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 was 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. The Partnership is no longer being charged these rates after November 9, 2017 as a result of the 2017 Asset Exchange Transaction with Oncor.

Taking power over the ERCOT network requires the Distribution Service Providers (DSPs) 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 DSP.

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, 2018 and 2017 totaled approximately $282,000 and $253,000, respectively. The cost is included in general and administrative expense in the Consolidated Statements of Operations. Retiree contributions to the plan totaled approximately $234,000 and $186,000 during the years ended December 31, 2018 and 2017, 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 item 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, 2018 and 2017are as follows:

In the postretirement benefit obligation regulatory liability at December 31, 2018, there is a $443,000 net loss that is expected to be recognized as a component of net periodic postretirement benefit cost in 2019.

The following sets forth the obligations, fair value of plan assets and funded status of the postretirement health care plan at December 31, 2018 and 2017:

(In thousand)		2018				2017
Benefit obligation, beginning of year	$		8,615		$		10,241
Service costs			4				38
Interest costs			262				377
Benefits paid			(710	)			(440	)
Actuarial (gain) loss			(1,130	)			537
Curtailment			-				(2,137	)
Benefit obligation, end of year			7,041				8,616
Fair value of plan assets			6,343				7,177
Accumulated postretirement benefit obligation	$		698		$		1,439

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, 2018 and 2017 were approximately $711,000 and $440,000, 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 and liabilities held by the trust as of December 31, 2018 and 2017

		December 31, 2018									December 31, 2017
(In thousands)		Level 1			Level 2			Level 3			Level 1				Level 2			Level 3
Cash and money balances	$		49	$		-	$		-	$		477		$		-	$		-
Mutual Funds			6,294			-			-			6,708				-		-
Other			-			-			-			(8	)			-		-
	$		6,343	$		-	$		-	$		7,177		$		-	$		-

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 $897,000 and $3.0 million during the years ended December 31, 2018 and 2017, 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, 2018 and 2017, the Partnership had approximately $131.8 million and $135.3 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, 2018 and 2017. The fair value of these borrowings is estimated using discounted cash flow analysis based on current market rates.

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, 2018
Long-term debt	$		155,342	$		-	$		155,114	$		-
December 31, 2017
Long-term debt			158,835			-			158,673			-

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 $540,000 and $759,000 during the years ended December 31, 2018 and 2017, 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, 2018:

On April 29, 2016, the Partnership filed a system-wide rate proceeding with the PUCT to update its rates (April Rate Case Filing) which was amended on December 30, 2016 (December Rate Case Filing) as a result of a preliminary order issued by the PUCT in October 2016., The December Rate Case Filing was dismissed on September 29, 2017, contingent on PUCT approval of the STM and the closing of the 2017 asset Exchange Agreement. See Note 2, 2017 Asset Exchange Agreement for additional information regarding the 2017 Asset Exchange Agreement.

On October 13, 2017, the PUCT issued an order approving the STM for the 2017 Asset Exchange Agreement and granting SDTS a CCN to continue to own and lease its assets to the Partnership. Also on October 13, 2017, the PUCT issued an order approving the settlement of Oncor’s rate case in Docket No. 46957 contingent on the closing of the 2017 Asset Exchange Agreement. The PUCT’s approval of the STM and Oncor’s rate case settlement were both conditions to the closing of the 2017 Asset Exchange Agreement.

Once the December Rate Case filing dismissal became effective, the Partnership and SDTS continued operating under their existing regulatory structure, and the current regulatory parameters remain in place until the next rate case, including an allowed return on equity of 9.7%, a capital structure of 55% debt and 45% equity and a cost of debt of 6.73%. The Partnership and SDTS will be required to file a new rate case in the calendar year 2020 with a test year ending December 31, 2019.

On February 27, 2018, the Partnership filed an update to its transmission cost of service rates under Docket No. 47649 in order to reflect an income tax allowance at the new 21% corporate federal income tax rate, due to the enactment of the TCJA. The Partnership has historically incorporated an income tax allowance in its MLAs at a 35% corporate federal income tax, and the Partnership’s existing lease supplements with SDTS reflect this assumption.

On February 6, 2018, Sharyland filed its request to recover the rate case expenses incurred in Docket’s No. 45414, 41723 and 42699. The amount requested included $7.9 million of expenses incurred by Sharyland and $474,000 incurred by the municipalities within Sharyland’s service territory who intervened in Docket No. 45414. This case was heard by an administrative law judge (ALJ) in August and the company received a proposal for decision from the ALJ in October. On December 7, 2018, the PUCT commissioner’s put this case on hold while the 2018 Sale and Asset Exchange Agreement is pending.

On October 18, 2018, the Partnership entered into the 2018 Sale and Asset Exchange Agreement with SU Investment Partners, L.P., Sempra, and Sempra Energy where Sempra will obtain a 50% limited partnership interest in Sharyland Holdings, which will own a 100% interest in the SU Investment. The Partnership also entered an Asset Exchange agreement with SDTS & Oncor to exchange GSPE and certain development projects in the Texas Panhandle and South Plains regions, including the LPL Project for SDTS’s South Texas Assets. Concurrently with the execution of the 2018 Sale and Asset Exchange Agreement and the Asset Exchange, Oncor entered into a definitive agreement to acquire InfraREIT, Inc. (the Oncor Merger). On November 30, 2018, the Partnership and SDTS filed a joint STM application Docket No. 48929 with Oncor and Sempra for approval of the SU Investment, the Asset Exchange and the Oncor Merger. See Note 2, 2018 Sale Asset Exchange for additional information regarding the SU Investment, the Asset Exchange and the Oncor Merger.

Texas Regional Entity (Texas RE) conducted a compliance audit of the Partnership for its transmission owner, transmission operator, and transmission planner functions. The audit includes recommendations, areas of concern and findings of potential noncompliance. Texas RE’s enforcement division will review the facts and circumstances to determine if there have been any violations of reliability standards, and if so, the appropriate mitigating activities and any penalties. The timeframe for concluding the enforcement activities is unknown.

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

(In thousands)		2018			2017
Supplemental cash flow information
Cash paid for interest	$		169,371	$		160,192
Cash paid for margin taxes			1,754			1,540
Non-cash change in regulatory pension costs			1,023			317
Non-cash investing and financing activities
Right of way additions to property, plant and equipment	$		-	$		407
Financing obligation incurred			65,743			137,172
Change in accrued additions to property, plant and equipment			893			1,011
Property, plant and equipment - net transferred to deferred charges - regulatory assets			1,590			-
Allowance for funds used during construction - debt			82			14

On January 18, 2019, the Partnership drew $5.0 million under its subordinated note with Loyal 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 22, 2019, 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,
	2018	2017
Transmission plant	1.29% - 3.14%	1.29% - 3.14%
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:
2019			196,718
2020			188,330
2021			8,659
2022 and Thereafter			4,540
Total future minimum lease payments	$		398,247

		December 31,
(In thousands)		2018			2017
Failed sale-lease back interest expense
Fixed portion of failed-leaseback interest	$		153,925	$		133,194
Variable portion of failed-leaseback interest			8,285			25,262
Failed sale-lease back interest expense	$		162,210	$		158,456

		Total
Year Ending December 31:
2019	$		34,513
2020			29,470
2021			7,151
2022			1,176
2023			124
Thereafter			1,575,099
Total financing obligation			1,647,533
Less: current portion of financing obligation			(34,513	)
Leased system under construction obligation			62,301
Lease deferral (Note 7)			23,793
Long-term lease obligation	$		1,699,114

(In thousands)		2018				2017
Defined benefit postretirement plan:
Net Gain	$		(3,724	)	$		(2,701	)
Total	$		(3,724	)	$		(2,701	)

	2018			2017
Discount rate used for year-end obligation		3.91	%		3.30	%
Discount rate used for net periodic benefit cost		3.30	%		4.00	%
Current medical cost trend rate for year-end obligation		7.00	%		7.25	%
Current medical cost trend rate for net periodic benefit cost		7.25	%		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	%