Exhibit 99.1

Offshore Gulf of Mexico Energy Services

Business of Enterprise Products Operating

LLC

Unaudited Combined Financial Statements for the

Three and Six Months Ended June 30, 2015 and 2014

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OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

INDEX TO UNAUDITED COMBINED FINANCIAL STATEMENTS

 

		Page No.
Unaudited Combined Balance Sheets as of June 30, 2015 and December 31, 2014			F-1
Unaudited Statements of Combined Operations for the Three and Six Months Ended June 30, 2015 and 2014			F-2
Unaudited Statements of Combined Cash Flows for the Six Months Ended June 30, 2015 and 2014			F-3
Unaudited Statements of Combined Equity for the Six Months Ended June 30, 2015 and 2014			F-4
Notes to Unaudited Combined Financial Statements			F-5

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OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

UNAUDITED COMBINED BALANCE SHEETS

(Dollars in millions)

 

		June 30,				December 31,
		2015				2014
ASSETS
Current assets
Cash and cash equivalents		$	0.9			$	2.0
Accounts receivable – trade, net of allowance for doubtful accounts of $0.4 at June 30, 2015, $0.5 at December 31, 2014			20.7				27.1
Accounts receivable – related parties			1.3				0.7
Prepaid expenses			3.1				1.5
Other current assets			0.5				0.4
Total current assets			26.5				31.7
Property, plant and equipment, net (see Note 4)			1,109.6				1,144.5
Investments in unconsolidated affiliates (see Note 5)			482.4				494.9
Intangible assets (see Note 6)			37.1				41.6
Goodwill (see Note 2)			53.5				82.0
Other assets			1.2				1.3
Total assets		$	1,710.3			$	1,796.0
LIABILITIES AND EQUITY
Current liabilities
Accounts payable – trade		$	6.6			$	5.5
Accounts payable – related parties			1.5				—
Accrued product payables			1.7				2.0
Current portion of asset retirement obligations			11.1				12.4
Deferred revenue			2.5				1.5
Other current liabilities			0.7				1.0
Total current liabilities			24.1				22.4
Noncurrent liabilities			94.2				94.6
Commitments and contingencies (see Note 8)
Equity (see Note 1)
Owners’ net investment			1,529.8				1,615.2
Noncontrolling interest			62.2				63.8
Total equity			1,592.0				1,679.0
Total liabilities and equity		$	1,710.3			$	1,796.0

The accompanying notes are an integral part of these Unaudited Combined Financial Statements.

 

F-1

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OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

UNAUDITED STATEMENTS OF COMBINED OPERATIONS

(Dollars in millions)

 

		For the Three Months Ended June 30,								For the Six Months Ended June 30,
		2015				2014				2015				2014
Revenues:
Pipeline transportation fees		$	28.0			$	30.1			$	56.5			$	59.3
Platform fees			4.1				5.6				8.7				11.1
Other revenues			8.0				10.2				16.0				19.9
Total revenues (see Note 2)			40.1				45.9				81.2				90.3
Costs and expenses:
Operating expenses			18.1				21.8				35.1				39.4
Depreciation and accretion expense			18.5				20.3				39.6				39.6
Amortization of intangible assets			2.2				2.5				4.5				5.1
Asset impairment charges			28.6				—				28.6				—
Gain on disposal of fixed assets			—				(5.6	)			—				(5.9	)
General and administrative costs			1.2				2.7				2.5				4.6
Total costs and expenses			68.6				41.7				110.3				82.8
Equity in income of unconsolidated affiliates			21.0				7.6				40.1				18.7
Operating income (loss) and net income (loss)			(7.5	)			11.8				11.0				26.2
Net loss attributable to noncontrolling interest			0.5				0.1				0.8				0.1
Net income (loss) attributable to owners		$	(7.0	)		$	11.9			$	11.8			$	26.3

The accompanying notes are an integral part of these Unaudited Combined Financial Statements.

 

F-2

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OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

UNAUDITED STATEMENTS OF COMBINED CASH FLOWS

(Dollars in millions)

 

		For the Six Months Ended June 30,
		2015				2014
Operating activities:
Net income		$	11.0			$	26.2
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and accretion expense			39.6				39.6
Amortization of intangible assets			4.5				5.1
Asset impairment charges			28.6				—
Equity in income of unconsolidated affiliates			(40.1	)			(18.7	)
Distributions from unconsolidated affiliates			52.3				32.0
Gain on disposition of assets, net			—				(5.9	)
Other noncash items			1.9				1.2
Changes in operating assets and liabilities:
Accounts receivable			5.8				(1.7	)
Other current assets			(1.7	)			2.3
Other assets			0.1				1.5
Accounts payable			0.2				(1.4	)
Accrued product payables			(0.3	)			—
Other current liabilities			(3.3	)			(2.1	)
Noncurrent liabilities			(1.0	)			—
Net cash provided by operating activities			97.6				78.1
Investing activities:
Additions to property, plant and equipment			(4.1	)			(7.7	)
Contributions in aid of construction costs			4.9				—
Proceeds from disposition of assets			0.2				12.0
Investments in unconsolidated affiliates			(1.8	)			(4.3	)
Return of excess investment in unconsolidated affiliates			2.0				—
Net cash provided by investing activities			1.2				—
Financing activities:
Cash distributions to owners, net			(99.1	)			(76.1	)
Cash distributions to noncontrolling interests			(0.8	)			(1.3	)
Net cash used in financing activities			(99.9	)			(77.4	)
Net increase (decrease) in cash			(1.1	)			0.7
Cash, beginning of period			2.0				1.8
Cash, end of period (see Note 1)		$	0.9			$	2.5

The accompanying notes are an integral part of these Unaudited Combined Financial Statements.

 

F-3

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OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

UNAUDITED STATEMENTS OF COMBINED EQUITY

(Dollars in millions)

 

		Owners’ Net Investment				Noncontrolling Interest				Total
Balance, December 31, 2014		$	1,615.2			$	63.8			$	1,679.0
Net income (loss)			11.8				(0.8	)			11.0
Cash distributions to owners, net			(99.1	)			—				(99.1	)
Cash distributions to noncontrolling interests			—				(0.8	)			(0.8	)
Other			1.9				—				1.9
Balance, June 30, 2015		$	1,529.8			$	62.2			$	1,592.0
		Owners’ Net Investment				Noncontrolling Interest				Total
Balance, December 31, 2013		$	1,739.2			$	66.9			$	1,806.1
Net income			26.3				(0.1	)			26.2
Cash distributions to owners, net			(76.1	)			—				(76.1	)
Cash distributions to noncontrolling interests			—				(1.3	)			(1.3	)
Other			1.2				—				1.2
Balance, June 30, 2014		$	1,690.6			$	65.5			$	1,756.1

The accompanying notes are an integral part of these Unaudited Combined Financial Statements.

 

F-4

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OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO UNAUDITED COMBINED FINANCIAL STATEMENTS

Except as noted in the context of each disclosure, dollar amounts presented in the tabular data

within these disclosures are stated in millions of dollars.

Note 1. Basis of Financial Statement Presentation and Description of Business

Key References Used in these Notes to Unaudited Combined Financial Statements

Unless the context requires otherwise, references to “we,” “us,” “our,” or “the Business” are intended to mean and include the combined businesses and operations of the Offshore Gulf of Mexico Energy Services Business of Enterprise Products Operating LLC.

References to “EPO” mean Enterprise Products Operating LLC, which is a wholly owned subsidiary of Enterprise Products Partners L.P. (“EPD”), and its consolidated subsidiaries. References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates.

As generally used in the energy industry and in these notes to combined financial statements, “MMcf/d” means million cubic feet per day and “MBPD” means thousands of barrels per day.

Basis of Financial Statement Presentation

The accompanying unaudited combined financial statements and related notes of the Business have been prepared from EPO’s separate historical accounting records. These unaudited combined financial statements have been prepared using EPO’s historical basis in the assets and liabilities of the Business and historical results of operations. The unaudited combined financial statements may not necessarily be indicative of the conditions that would have existed or the results of operations of the Business if it had been operated as an unaffiliated entity. See Note 7 for information regarding related party transactions of the Business.

Our unaudited combined financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all normal and recurring intercompany accounts and transactions. Third party or affiliate ownership interests in our controlled subsidiaries are presented as noncontrolling interests.

Within the energy industry, it is customary for parties to own undivided interests in certain fixed assets rather than structuring a separate legal entity to own the asset and then acquiring equity interests in that company. We proportionately consolidate our undivided interest in such assets. As a result, our unaudited combined financial statements reflect our share of the assets, liabilities, revenues and expenses attributable to such fixed assets.

If the entity is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50%, unless our interest is so minor that we have virtually no influence over the investee’s operating and financial policies. For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee’s operating and financial policies. In preparing our unaudited combined financial statements, we eliminate our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates to the extent such amounts remain on our Unaudited Combined Balance Sheets (or those of our equity method investments) in inventory or similar accounts.

 

F-5

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The combined financial statements as of June 30, 2015 and for the three and six months ended June 30, 2015 and 2014 are unaudited. In the opinion of management, the unaudited interim combined financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States of America (“U.S.”) and include all adjustments necessary to present fairly the financial position and results of operations of the Business for the respective interim periods. Interim financial results are not necessarily indicative of the results to be expected for an annual period.

All statistical data (e.g., pipeline mileage, processing capacity and similar operating metrics) in these notes to are unaudited.

Since a single direct owner relationship does not exist among the combined entities, we present our net investment in the entities (i.e., owners’ net investment) in lieu of parent or owners’ equity in the unaudited combined financial statements.

With the exception of our Independence Hub, LLC subsidiary (“Independence Hub”), the Business operates within EPO’s cash management program; therefore, all cash receipts and payments of our subsidiaries (excluding Independence Hub) are managed through EPO’s cash accounts. Our Unaudited Statements of Combined Cash Flows present the operating and investing cash flows of our Business, with any transfers of excess net cash between subsidiaries under EPO’s cash management program and EPO reflected as a distribution to owners. As a result, cash and cash equivalents at the end of each period is attributable solely to balances held by Independence Hub.

On July 16, 2015, EPO announced the execution of a Purchase and Sale Agreement with Genesis Energy, L.P. (“Genesis”), whereby Genesis agreed to acquire our Business for approximately $1.5 billion in cash. See Note 3 for additional information regarding impairment charges related to this transaction.

Description of the Business

We serve some of the most active drilling and development regions, including deepwater production fields, in the northern Gulf of Mexico offshore Texas, Louisiana, Mississippi and Alabama. As of December 31, 2014, our integrated asset network included approximately 2,350 miles of offshore natural gas and crude oil pipelines and six offshore hub platforms.

Note 2. Summary of Significant Accounting Policies

Allowance for Doubtful Accounts

Our allowance for doubtful accounts is based on the specific identification of accounts receivable where the underlying amounts due have not been collected within 90 days. In addition, we may also increase the allowance account in response to the specific identification of customers involved in bankruptcy proceedings and those experiencing other financial difficulties. On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses. Historically, losses attributable to uncollectible accounts have not been material to our unaudited combined financial statements.

 

F-6

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The following table presents our allowance for doubtful accounts activity for the period indicated:

 

		For the Six Months Ended June 30,
		2015				2014
Balance, beginning of period		$	0.5			$	0.4
Charged to costs and expenses			0.5				0.1
Deductions			0.6				—
Balance, end of period		$	0.4			$	0.5

Asset Retirement Obligations

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related property, plant and equipment asset. ARO amounts are measured at their estimated fair value using expected present value techniques. Over time, the discounted ARO liability is accreted to its expected settlement value (through “accretion expense”) and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts.

See Note 4 for additional information regarding our AROs.

Cash and Cash Equivalents

As presented on our Unaudited Combined Balance Sheets and Unaudited Statements of Combined Cash Flows, cash and cash equivalents at the end of each period is attributable solely to balances held by Independence Hub. These balances represent unrestricted cash of Independence Hub and may also include highly liquid investments with original maturities of less than three months from the date of purchase.

Contingencies

Certain conditions may exist as of the date our unaudited combined financial statements are issued, which may result in a loss to us depending on whether one or more future events occur or fail to occur. Management and its legal counsel assess such contingent liabilities on a quarterly basis, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived merits of such matters as well as the amount of relief sought or expected to be sought therein.

If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of the liability can be estimated, then the estimated liability would be accrued in our financial statements. If the assessment indicates that a potentially material loss contingency is not probable, but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, would be disclosed.

Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the nature of the guarantee would be disclosed.

 

F-7

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Current Assets and Current Liabilities

We present, as individual captions on our Unaudited Combined Balance Sheets, all components of current assets and current liabilities that exceed 5% of total current assets and liabilities, respectively.

Environmental Costs

Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. We did not have any environmental remediation liabilities recorded at June 30, 2015 or December 31, 2014.

Estimates

Preparing our unaudited combined financial statements in conformity with GAAP requires management to make estimates and assumptions that effect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the unaudited combined financial statements and the reported amounts of revenues and expenses during the reporting period. Our most significant estimates relate to (i) the useful lives and depreciation/amortization methods used for fixed and identifiable intangible assets; (ii) measurement of fair value and projections used in impairment testing of fixed and intangible assets (including goodwill); (iii) contingencies; and (iv) revenue and expense accruals.

Actual results could differ materially from our estimates. On an ongoing basis, we review our estimates based on currently available information. Any changes in the facts and circumstances underlying our estimates may require us to update such estimates, which could have a material impact on our unaudited combined financial statements.

Equity-Based Compensation

We have no employees. Our operating functions and general and administrative support services are provided pursuant to an administrative services agreement (“ASA”) between EPCO and EPO (see Note 7) or by other service providers. Certain key employees of EPCO that are either wholly or partially dedicated to our Business also participate in long-term compensation plans managed by EPCO. These plans include the issuance of equity-based compensation (e.g., restricted common units of EPD), of which we are charged for our allocated share of the fair value of such awards to the extent that the recipients perform services on our behalf.

The amount of equity-based compensation allocable to our Business was $1.0 million and $1.1 million for the three months ended June 30, 2015 and 2014, respectively. For each of the six months ended June 30, 2015 and 2014, the amount of equity-based compensation allocable to our Business was $1.9 million, respectively.

Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or be paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. See Note 3 for information regarding the fair value of financial instruments and nonrecurring fair value measurements.

 

F-8

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Goodwill

Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in a business combination. The goodwill presented on our Unaudited Combined Balance Sheets is attributable to a business combination that occurred in 2004. The following table presents changes in the carrying amount of goodwill during the period indicated:

 

Balance at December 31, 2014		$	82.0
Impairment of goodwill balance in connection with sale of Business to Genesis (see Note 3)			(28.5	)
Balance at June 30, 2015		$	53.5

Goodwill is not amortized; however, it is subject to annual impairment testing at the end of each fiscal year, and more frequently, if circumstances indicate it is probable that the fair value of goodwill is below its carrying amount. If such circumstances occur, the estimated fair value of the reporting unit to which the goodwill is assigned is determined and compared to its carrying value. If the fair value of the reporting unit is less than its carrying value (including associated goodwill amounts), a charge to earnings is recorded to reduce the carrying value of the goodwill to its implied fair value. Our integrated offshore activities comprise a single reporting unit for purposes of goodwill testing.

When testing goodwill for impairment, our fair value estimates are based on a number of management assumptions, including (i) discrete financial forecasts for our offshore assets, including operating margins and throughput volumes; (ii) continuation of existing environmental and safety regulations that allow us to operate our assets in a prudent manner; (iii) tropical weather patterns that do not materially disrupt our operations during the forecast period; (iv) no governmental actions that shut-in Gulf of Mexico production activities (e.g., the moratorium put in place following the third-party Deepwater Horizon incident in 2010); (v) long-term growth rates for cash flows beyond the discrete forecast period; and (vi) appropriate discount rates. We believe that these assumptions are consistent with those that market participants would make in estimating the fair value of our Business.

Impairment Testing for Long-Lived Assets

Long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written-down to their estimated fair values. The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset’s carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset’s carrying value over its estimated fair value is recorded. Fair value is defined as the price that would be received to sell an asset or be paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques.

See Note 3 for information regarding impairment charges related to long-lived assets during the periods covered by this report.

Impairment Testing for Unconsolidated Affiliates

We evaluate our equity method investments for impairment when events or changes in circumstances indicate that there is a loss in value of the investment attributable to an other than temporary decline. In the event we determine that the loss in value of an investment is an other than temporary decline, we record a charge to equity earnings to adjust the carrying value of the investment to its estimated fair value.

 

F-9

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Income Taxes

For federal income tax purposes, our combined operations are considered pass-through entities. As a result, our unaudited combined financial statements do not provide for such taxes and our owners are responsible for their allocable share of our taxable income.

Property, Plant and Equipment

Property, plant and equipment is recorded at historical cost. Expenditures for additions, improvements and other enhancements to property, plant and equipment are capitalized, and minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred. When property, plant and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in results of operations for the respective period.

In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the periods it benefits. Our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of an asset. Our estimate of depreciation expense incorporates management’s assumptions regarding the useful economic lives and residual values of our assets.

Our assumptions regarding the useful economic lives and residual values of our assets may change in response to new facts and circumstances, which would prospectively impact our depreciation expense amounts. Examples of such circumstances include, but are not limited to: (i) changes in laws and regulations that limit the estimated economic life of an asset; (ii) changes in technology that render an asset obsolete; (iii) changes in expected salvage values or (iv) significant changes in the forecast life of the applicable resource basins, if any.

See Note 4 for additional information regarding our property, plant and equipment.

Revenue Recognition

We recognize revenue from our customers when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the buyer’s price is fixed or determinable and (iv) collectibility is reasonably assured. Amounts billed in advance of the period in which the service is rendered or product delivered are recorded as deferred revenue.

Revenue from our offshore pipelines is generally based upon a fixed fee per unit of volume gathered or transported multiplied by the volume delivered. Transportation fees are based either on contractual arrangements or tariffs regulated by the Federal Energy Regulatory Commission (“FERC”). Revenue associated with these fee-based contracts and tariffs is recognized when volumes have been delivered.

Revenues from offshore platform services generally consist of demand fees and commodity charges. Revenues from offshore platform services are recognized in the period the services are provided. Demand fees represent charges to customers served by our offshore platforms regardless of the volume the customer actually delivers to the platform. Revenue from commodity charges is based on a fee per unit of volume delivered to the platform multiplied by the total volume of each product delivered. Contracts for platform services often include both demand fees and commodity charges, but demand fees generally expire after a contractually fixed period of time and in some instances may be subject to cancellation by customers.

Fees we earn through the provision of management or similar services to our unconsolidated affiliates are presented as a component of “Other revenues” on our Unaudited Statements of Combined Operations.

 

F-10

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Subsequent Events

In preparing these combined financial statements, we have evaluated subsequent events for potential recognition or disclosure through August 12, 2015, the issuance date of the financial statements.

Note 3. Fair Value Measurements

Fair Values of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable and accounts payable. The carrying values of accounts receivable and accounts payable approximate their respective fair values due to their short term nature. We do not utilize derivative instruments in our operations.

Fair value is the amount that would be received in an asset sale or paid to transfer a liability in an orderly transaction between unaffiliated market participants. Assets and liabilities measured at fair value are categorized based on whether the inputs are observable in the market and the degree that the inputs are observable. The categorization of financial instruments within the valuation hierarchy is based on the lowest level of input that is significant to the fair value measurement. The hierarchy is prioritized into three levels (with Level 3 being the lowest and most subjective) defined as follows:

 

•

Level 1: Inputs are based on quoted market prices for identical assets or liabilities in active markets at the measurement date.

 

•

Level 2: Inputs include quoted prices for similar assets or liabilities in active markets and/or quoted prices for identical or similar assets or liabilities in markets that are not active near the measurement date.

 

•

Level 3: Inputs include management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. The inputs are unobservable in the market and significant to the valuation.

 

F-11

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Impairment Charge in connection with Sale of Business to Genesis

As presented in Note 1, we announced the execution of a Purchase and Sale Agreement with Genesis on July 16, 2015 whereby Genesis agreed to acquire our Business from EPO. The sales price was approximately $1.53 billion in cash and the transaction closed on July 24, 2015. As a result of this transaction, we incurred an impairment charge at June 30, 2015 of $28.5 million, which represents the excess of the carrying value of our net assets, including goodwill, over their implied fair value as represented by the negotiated selling price. The following table summarizes our non-recurring fair value measurements:

 

						Fair Value Measurements Using
		Carrying Value at Period End				Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total Impairment Loss
Impairment of goodwill attributable to long-lived assets held and used		$	53.5			$	—			$	—			$	28.5			$	28.5
Impairment of long-lived assets disposed of other than by sale			—				—				—				0.1				0.1
Total		$	53.5			$	—			$	—			$	28.6			$	28.6

The following table summarizes the carrying values of our assets prior to and after the non-cash impairment charge related to the sale of our Business to Genesis:

 

		Initial Carrying Value at June 30, 2015				Non-Cash Impairment Charge				Adjusted Carrying Value at June 30, 2015
Current assets		$	26.5			$	—			$	26.5
Property, plant and equipment, net			1,109.6				—				1,109.6
Investments in unconsolidated affiliates			482.4				—				482.4
Intangible assets, net			37.1				—				37.1
Goodwill			82.0				(28.5	)			53.5
Other assets			1.2				—				1.2
Total Assets		$	1,738.8			$	(28.5	)		$	1,710.3

 

F-12

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Note 4. Property, Plant and Equipment

The historical costs of our property, plant and equipment and related accumulated depreciation balances were as follows at the dates indicated:

 

		Estimated Useful Life in Years				June 30,				December 31,
						2015				2014
Natural gas pipelines and related equipment (1)			5 - 35			$	795.7			$	805.7
Offshore platforms (2)			8 - 35				630.3				630.2
Crude oil pipelines and related equipment (3)			10 - 35				300.2				300.2
Other offshore fixed assets (4)			5 - 29				8.7				8.6
Construction in progress							6.7				5.4
Total							1,741.6				1,750.1
Less accumulated depreciation							(632.0	)			(605.6	)
Property, plant and equipment, net						$	1,109.6			$	1,144.5

 

(1)	In general, the estimated useful lives of major assets within this category are: natural gas pipelines, 11-35 years; processing equipment, 14 years; communication equipment, 7-10 years; office furniture and equipment, 10-15 years; vehicles, 5-6 years; and hardware and software, 5 years.

(2)	The largest asset classified within this group, the Independence Hub platform, has a 20 year estimated useful life.

(3)	In general, the estimated useful lives of major assets within this category are: crude oil pipelines, 20-35 years; and communication equipment, 10 years.

(4)	In general, the estimated useful lives of major assets within this category are: underwater pipeline emergency equipment, 29 years; communication equipment, 10 years; and vehicles, 5-6 years.

The following table summarizes our non-cash depreciation expense for each of the periods indicated:

 

		For the Three Months Ended June 30,								For the Six Months Ended June 30,
		2015				2014				2015				2014
Depreciation expense		$	18.1			$	18.1			$	36.3			$	36.2

Sale of Typhoon Oil Pipeline in June 2014

In June 2014, we sold the Typhoon crude oil pipeline for cash proceeds of $12.0 million. As a result, net income for the three and six months ended June 30, 2014 includes a $5.6 million gain from the sale of this asset.

Asset Retirement Obligations

We record AROs in connection with legal requirements to perform specified retirement activities under contractual arrangements and/or governmental regulations. In general, U.S. federal regulations stipulate that energy infrastructure located in the Gulf of Mexico (e.g., pipelines, platforms, production wells, etc.) must be removed when hydrocarbons are no longer being produced. As a practical matter, the agencies overseeing pipeline abandonment activities typically grant approval for operators to remove all hydrocarbons from the pipeline, cut and remove any risers, remove sea valves, fill the pipelines with sea water and abandon the pipeline in-place. With regards to offshore platforms, agencies generally allow operators to abandon in-place the lower portion of platforms with the remaining portion being removed and disposed of. Lastly, agencies require the plugging and abandonment of all offshore oil and gas wells when hydrocarbons are no longer produced.

 

F-13

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Certain segments of our pipeline systems and those of our unconsolidated affiliates are constructed in or near defined anchorages, shipping lanes and state waters under permits issued by the U.S. Army Corps of Engineers (the “CoE”). These permits generally require that, upon abandonment of a pipeline segment under the CoE’s jurisdiction, we restore the location to its pre-existing condition. Historically, the CoE has allowed pipeline owners to abandon pipeline segments in-place due to environmental considerations, water depths involved and other factors. Generally, we have assumed, for purpose of determining our ARO liabilities, that the CoE will allow for such pipeline segments to be abandoned in place primarily due to the significant adverse environmental impacts that would result from removal activities and the water depths involved, including deep water Gulf of Mexico locations unless otherwise notified by the CoE.

We have been notified by the CoE to fully remove two pipeline segments included in our Matagorda Gathering System that we had originally requested to abandon in-place. We are in the process of appealing the CoE request. Our ARO liability balance with respect to the Matagorda Gathering System is based on our assessment of the probabilities that we would either (i) be required to fully remove pipeline segments or (ii) be allowed to abandon such segments in place. Our recorded ARO liability balance for the Matagorda Gathering System, including those amounts associated with the potential removal of pipeline segments under the CoE’s jurisdiction, totaled $49.9 million and $49.3 million at June 30, 2015 and December 31, 2014, respectively. If we assume the full removal of all impacted pipeline segments of the Matagorda Gathering System, our historical ARO liability balances for this pipeline system would increase by approximately $42.9 million (unaudited) and $42.1 million at June 30, 2015 and December 31, 2014, respectively.

The following table presents information regarding our AROs for the periods indicated:

 

		For the Six Months Ended June 30,
		2015				2014
ARO liability, beginning of period		$	107.0			$	103.7
Liabilities settled			(2.9	)			(2.3	)
Revisions in estimated cash flows			(1.3	)			1.0
Accretion expense			2.5				2.4
ARO liability, end of period		$	105.3			$	104.8

AROs are measured at their estimated fair value using expected present value techniques. Our estimates of future settlement values for AROs are based on inflation-adjusted asset retirement costs (based on current regulations) expected to be incurred at the end of the expected economic life of the underlying Gulf of Mexico resource basins.

Property, plant and equipment at June 30, 2015 and December 31, 2014 includes $11.0 million and $11.4 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.

The following table presents our forecast of accretion expense for the periods indicated:

 

Remainder of 2015		2016		2017		2018		2019
$2.3		$4.8		$4.9		$5.0		$5.3

 

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Note 5. Investments in Unconsolidated Affiliates

Equity investments with industry partners are a significant component of our business strategy. They are a means by which we conduct our operations to align our interests with those of customers and/or suppliers. This method of operation enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed.

The following table presents the investment balances for each of our unconsolidated affiliates at the dates indicated:

 

Investee		Ownership Interest				June 30,				December 31,
						2015				2014
Southeast Keathley Canyon Pipeline Company L.L.C.			50.0	%		$	148.4			$	147.3
Poseidon Oil Pipeline Company, L.L.C.			36.0	%			28.0				31.8
Cameron Highway Oil Pipeline Company			50.0	%			195.5				201.3
Deepwater Gateway, L.L.C.			50.0	%			77.4				79.6
Neptune Pipeline Company, L.L.C.			25.7	%			33.1				34.9
Total						$	482.4			$	494.9

The following table presents our equity in the income of unconsolidated affiliates for the periods indicated:

 

Investee		For the Three Months Ended June 30,								For the Six Months Ended June 30,
		2015				2014				2015				2014
Southeast Keathley Canyon Pipeline Company L.L.C. (1)		$	9.4			$	(0.1	)		$	17.5			$	(0.1	)
Poseidon Oil Pipeline Company, L.L.C.			8.6				5.0				15.6				11.0
Cameron Highway Oil Pipeline Company			3.1				3.1				7.2				7.8
Deepwater Gateway, L.L.C.			0.2				(0.3	)			0.5				0.4
Neptune Pipeline Company, L.L.C.			(0.3	)			(0.1	)			(0.7	)			(0.4	)
Total		$	21.0			$	7.6			$	40.1			$	18.7

 

(1)	Equity earnings commenced when the pipeline was completed in July 2014.

The following table presents our cash investments in unconsolidated affiliates for the periods indicated:

 

Investee		For the Three Months Ended June 30,								For the Six Months Ended June 30,
		2015				2014				2015				2014
Southeast Keathley Canyon Pipeline Company L.L.C.		$	—			$	2.1			$	1.8			$	4.3

 

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The following table presents cash distributions received from unconsolidated affiliates for the periods indicated:

 

Investee		For the Three Months Ended June 30,								For the Six Months Ended June 30,
		2015				2014				2015				2014
Southeast Keathley Canyon Pipeline Company L.L.C.		$	8.6			$	—			$	16.1			$	—
Poseidon Oil Pipeline Company, L.L.C.			9.9				7.2				19.4				14.8
Cameron Highway Oil Pipeline Company			5.7				5.5				13.0				11.8
Deepwater Gateway, L.L.C.			1.7				1.8				2.7				3.8
Neptune Pipeline Company, L.L.C.			0.3				0.8				1.1				1.6
Total		$	26.2			$	15.3			$	52.3			$	32.0

The following tables present summarized aggregate balance sheet and income statement data for our unconsolidated affiliates at the dates and for the periods indicated (on a 100% basis):

 

		June 30,				December 31,
		2015				2014
Balance sheet data:
Current assets		$	49.9			$	42.0
Property, plant and equipment, net			1,274.3				1,311.1
Other assets			2.4				2.9
Total assets		$	1,326.6			$	1,356.0
Current liabilities		$	28.2			$	26.0
Long-term debt			195.3				195.3
Other liabilities			9.8				9.6
Equity			1,093.3				1,125.1
Total liabilities and equity		$	1,326.6			$	1,356.0

 

		For the Three Months Ended June 30,								For the Six Months Ended June 30,
		2015				2014				2015				2014
Income statement data:
Revenues		$	78.9			$	46.0			$	150.8			$	97.5
Operating income			49.6				19.5				93.2				48.2
Interest expense			1.1				0.8				2.3				1.5
Net income			48.5				19.1				91.0				47.0

Southeast Keathley Canyon Pipeline Company L.L.C.

Southeast Keathley Canyon Pipeline Company L.L.C. (“SEKCO”) is a Delaware limited liability company formed in December 2011 to design, construct, own and operate an unregulated offshore crude oil pipeline system (the “SEKCO Oil Pipeline”) located in the deepwater central Gulf of Mexico. SEKCO is owned 50% by Manta Ray Gathering Company, L.L.C., an indirect wholly owned subsidiary of EPO (“Manta Ray”), and 50% by a subsidiary of Genesis.

 

F-16

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The SEKCO Oil Pipeline is a 145-mile, 18-inch diameter crude oil gathering pipeline located in the southern Keathley Canyon area of the deepwater central Gulf of Mexico. The pipeline serves the Lucius production area in southern Keathley Canyon and has a crude oil transportation capacity of 115 thousand barrels per day (unaudited). In addition, the SEKCO Oil Pipeline connects the third-party owned Lucius Spar floating production facility to a junction platform at South Marsh Island 205 that is part of the crude oil pipeline system owned by Poseidon Oil Pipeline Company, L.L.C. Construction of the SEKCO Oil Pipeline was completed in July 2014. EPO managed the construction process and currently serves as operator of the pipeline. Crude oil shipments on the SEKCO Oil Pipeline commenced in January 2015 when the Lucius development started operations.

SEKCO has entered into long-term firm basis pipeline capacity reservation agreements with the Lucius producers. The term of these agreements is 20 years (July 2014 through June 2034), which corresponds to the period of dedicated production from the Lucius producers under the agreements.

Contribution of pipeline assets to SEKCO

In 2013, we contributed 47 miles of existing pipeline assets (the southern section of the Phoenix pipeline) to SEKCO having a carrying value and fair value at the time of the contribution of $33.8 million and $80.0 million, respectively. Using the straight line method, we are amortizing the $46.2 million gain on the contribution as an increase in equity earnings over a period of 20 years, which is the expected economic life of the contributed asset. Amortization of this gain increased our equity earnings from SEKCO by $0.6 million and $1.2 million for the three and six months ended June 30, 2015, respectively (amortization commenced in July 2014).

Poseidon Oil Pipeline Company, L.L.C.

Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”) is a Delaware limited liability company formed in February 1996 to design, construct, own and operate an unregulated crude oil pipeline system located in the central Gulf of Mexico offshore Louisiana. Poseidon is owned (i) 36% by Poseidon Pipeline Company, L.L.C. (an indirect wholly owned subsidiary of EPO), (ii) 36% by Equilon Enterprises LLC (d/b/a Shell Oil Products U.S.) and (iii) 28% by a subsidiary of Genesis.

The Poseidon Oil Pipeline System (the “Poseidon Pipeline”) gathers crude oil production from the outer continental shelf and deepwater areas of the Gulf of Mexico offshore Louisiana for delivery to onshore locations in south Louisiana. The Poseidon Pipeline system extends 366 miles and has an approximate capacity of 430 thousand barrels per day (unaudited). The system includes a pipeline junction platform located at South Marsh Island 205 (“SMI-205”), which connects with the SEKCO Oil Pipeline. Manta Ray serves as operator of the Poseidon Pipeline. Poseidon earns fees from providing crude oil handling services to producers.

At SMI-205, the SEKCO Oil Pipeline interconnects with the Poseidon Pipeline. Like SEKCO, Poseidon has entered into long-term pipeline capacity reservation agreements with the Lucius producers. The term of these agreements is 20 years (July 2014 through June 2034), which corresponds to the period of dedicated production from the Lucius producers under the agreements.

In September 2014, Poseidon completed significant capital projects related to its SMI-205 platform and equipment that it owns on the Ship Shoal 332A platform owned by Manta Ray. These expansion projects were undertaken to support Poseidon’s crude oil handling obligations to the Lucius producers and were financed with operating cash flows and borrowings under Poseidon’s revolving credit facilities.

Poseidon’s revolving credit facilities

Borrowings under Poseidon’s revolving credit facilities are primarily used to fund spending on capital projects. In April 2011, Poseidon entered into a revolving bank credit facility that had an initial borrowing capacity of $125

 

F-17

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million, which was increased to $225 million by August 2013. The April 2011 credit facility was terminated when Poseidon entered into its February 2015 revolving credit facility. The principal balance of $186.8 million that was outstanding under the April 2011 credit facility was refinanced under the February 2015 credit facility. The February 2015 credit facility is non-recourse to Poseidon’s owners and secured by its assets.

The February 2015 credit facility contains customary covenants such as restrictions on debt levels, liens, guarantees, mergers, sale of assets and distributions to owners. A breach of any of these covenants could result in acceleration of the maturity date of Poseidon’s debt. Poseidon was in compliance with the terms of its credit agreement for all periods presented in these unaudited combined financial statements.

Cameron Highway Oil Pipeline Company

Cameron Highway Oil Pipeline Company (“Cameron Highway”) is a Delaware general partnership formed in June 2003 to construct, install, own and operate an unregulated crude oil pipeline system located in the central Gulf of Mexico offshore Texas and Louisiana. Cameron Highway is owned 50% by Cameron Highway Pipeline I, L.P. (an indirect wholly owned subsidiary of EPO) and 50% by subsidiaries of Genesis.

The Cameron Highway pipeline system gathers production from deepwater areas of the central Gulf of Mexico, primarily from the South Green Canyon area, for delivery to markets in southeast Texas. The Cameron Highway system extends 374 miles and has an approximate transportation capacity of 295 thousand barrels per day (unaudited). The system includes pipeline junction platforms located at High Island A5 and Ship Shoal 332B. Manta Ray serves as operator of the Cameron Highway system.

Cameron Highway earns fees from providing crude oil handling services to producers. The Cameron Highway pipeline system is supported by life of lease dedications by certain producers (BP Exploration & Production Inc., BHP Billiton Ltd. (“BHP”), PXP Offshore LLC and Chevron USA Inc.) in the Holstein, Mad Dog and Atlantis fields and by Anadarko Petroleum Corporation (“Anadarko”) with respect to its production from the Constitution and Ticonderoga fields. In addition, Cameron Highway handles crude oil production from the Cottonwood field for Petrobras America Inc. and the Shenzi field for BHP.

Deepwater Gateway, L.L.C.

Deepwater Gateway, L.L.C. (“Deepwater Gateway”) is a Delaware limited liability company formed in June 2002 to construct, install and own the Marco Polo tension leg platform and related equipment. Deepwater Gateway is owned 50% by Manta Ray and 50% by Helix Energy Solutions Group, Inc. (“HESG”).

The Marco Polo platform, which is located approximately 180 miles offshore Louisiana in the Gulf of Mexico, is designed to process up to 120 thousand barrels of oil per day and 300 million cubic feet per day of natural gas (unaudited). Deepwater Gateway earns a fee for providing oil and gas processing services to certain producers (the “Marco Polo producers”) in the Marco Polo field (Green Canyon Block 608), Ghengis Khan Field (Green Canyon Block 652) and the K2 Fields (Green Canyon Blocks 518, 562 and 606) under life-of-lease production dedications. The Marco Polo producers include Anadarko, Eni Petroleum US LLC, ConocoPhillips Company, BHP Billiton Petroleum (Deepwater) Inc., MCX Gulf of Mexico, LLC, NIPPON Oil Exploration U.S.A. Limited, Hess Corporation, Repsol E&P USA Inc. and Ecopetrol America Inc.

Anadarko operates the Marco Polo platform and Manta Ray provides us technical and administrative services related to the operation of the platform.

 

F-18

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As owners of Deepwater Gateway, Manta Ray and HESG are individually responsible for maintaining insurance coverage on the Marco Polo platform (up to their respective 50% membership interests) with respect to general property damage risks other than damage attributable to named windstorm events. The Marco Polo producers reimburse Deepwater Gateway for the costs of this insurance. In addition, the Marco Polo producers agreed to provide Deepwater Gateway with $392 million of aggregate insurance coverage for named windstorm events through May 2015, which increased to $542 million for the annual policy period beginning in June 2015.

Neptune Pipeline Company, L.L.C.

Neptune Pipeline Company, LLC (“Neptune”) owns a 100% member interest in Manta Ray Offshore Gathering Company, LLC (“MROGC”) and Nautilus Pipeline Company, LLC (“Nautilus”). Neptune was formed in January 1997 to acquire, construct, own and operate the Manta Ray Offshore Gathering System, which is owned by MROGC, and the Nautilus System, which is owned by Nautilus. Neptune is owned 74.33% by Enbridge Offshore Gas Transmission and 25.67% by Sailfish Pipeline Company, LLC, a wholly owned subsidiary of EPO.

The Manta Ray Offshore Gathering System (or “Manta Ray System”) consists of 237 miles of unregulated natural gas gathering pipelines having an approximate transportation capacity of 800 million cubic feet per day (unaudited). The Manta Ray System gathers natural gas from producing fields located in the Green Canyon, Southern Green Canyon, Ship Shoal, South Timbalier and Ewing Bank areas of the Gulf of Mexico for delivery to downstream pipelines, including the Nautilus System. The Manta Ray System includes two offshore pipeline junction platforms.

The Nautilus System consists of a 101 mile natural gas pipeline with an approximate transportation capacity of 600 million cubic feet per day (unaudited). The Nautilus System connects the Manta Ray System and EPO’s Anaconda Gathering System to natural gas processing facilities located onshore in south Louisiana.

Revenues from the transportation of natural gas on the Manta Ray System and Nautilus System are recognized upon delivery of natural gas from the pipeline systems. The transportation fees charged by Nautilus are regulated by the FERC.

We believe that our current investment in Neptune is supported by expected future production growth from the eastern Walker Ridge area of the Gulf of Mexico.

Excess Cost

The price we paid to acquire our initial ownership interests in Poseidon and Cameron Highway exceeded our proportionate share of each investee’s net assets. These excess cost amounts are attributable to the fair value of the underlying tangible assets of these entities exceeding their respective book carrying values at the time of our acquisition of ownership interests in these entities. We amortize such excess cost amounts as a reduction to equity earnings in a manner similar to depreciation.

The following table presents the unamortized excess cost amounts for Poseidon and Cameron Highway that are included in the overall investment balance for each investee at the dates indicated:

 

		June 30,				December 31,
		2015				2014
Poseidon		$	7.3			$	7.9
Cameron Highway			1.1				1.1
Total		$	8.4			$	9.0

 

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Our amortization of excess cost amounts were $0.3 million for both the three months ended June 30, 2015 and 2014, respectively. For both the six months ended June 30, 2015 and 2014, our amortization of excess cost was $0.6 million, respectively. The following table presents our forecast of excess cost amortization expense for the periods indicated:

 

Remainder of 2015		2016		2017		2018		2019
$0.5		$1.1		$1.1		$1.1		$1.1

Note 6. Intangible Assets

Our identifiable intangible assets primarily consist of customer relationships. These intangible assets represent the estimated economic value we assigned to customer relationships acquired in connection with historical business combinations whereby (i) we acquired information about or access to customers and now have the ability to provide services to them and (ii) the customers now have the ability to make direct contact with us. Customer relationships may arise from contractual arrangements (such as service contracts) and through means other than contracts, such as through regular contact by sales or service representatives.

Customer relationship intangible assets are amortized to earnings using a method that closely resembles the pattern in which the economic benefits of the associated offshore hydrocarbon resource basins are expected to be produced. The amortization period for these intangible assets ranges from 11 to 33 years. The following table presents our forecast of amortization expense for our intangible assets for the periods indicated:

 

Remainder of 2015		2016		2017		2018		2019
$3.7		$4.7		$4.1		$3.6		$3.2

The following table summarizes our intangible assets at the dates indicated:

 

		June 30, 2015
		Gross Value				Accumulated Amortization				Carrying Value
Customer relationships		$	195.8			$	(159.4	)		$	36.4
Other			1.2				(0.5	)			0.7
Total		$	197.0			$	(159.9	)		$	37.1
		December 31, 2014
		Gross Value				Accumulated Amortization				Carrying Value
Customer relationships		$	195.8			$	(154.9	)		$	40.9
Other			1.2				(0.5	)			0.7
Total		$	197.0			$	(155.4	)		$	41.6

 

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The following table presents amortization expense for our intangible assets for the periods indicated:

 

		For the Three Months Ended June 30,								For the Six Months Ended June 30,
		2015				2014				2015				2014
Customer relationships		$	2.2			$	2.5			$	4.5			$	5.1
Other			—				—				—				—
Total		$	2.2			$	2.5			$	4.5			$	5.1

Note 7. Related Party Transactions

The following table summarizes our related party revenue and expense transactions for the periods indicated:

 

		For the Three Months Ended June 30,								For the Six Months Ended June 30,
		2015				2014				2015				2014
Revenues:
EPO and affiliates		$	0.1			$	1.2			$	0.4			$	3.4
Unconsolidated affiliates			4.2				6.1				8.5				11.9
Total		$	4.3			$	7.3			$	8.9			$	15.3
Costs and expenses:
EPO and affiliates		$	3.4			$	5.6			$	7.6			$	10.9
Unconsolidated affiliates			—				—				0.3				—
Total		$	3.4			$	5.6			$	7.9			$	10.9

Related party accounts receivables and accounts payables presented on our Combined Balance Sheets are with our unconsolidated affiliates. We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties.

Allocation of Costs from EPO

We have no employees. Our operating functions and general and administrative support services are provided pursuant to the ASA between EPCO and EPO or by other service providers. We are allocated a reasonable portion of the costs incurred by EPO under the ASA based on our use of such services. As it relates to our Business, the significant terms of the ASA are as follows:

 

•

EPCO provides operating, general and administrative services to EPO at levels necessary to manage and operate our Business in accordance with prudent industry practices. EPCO employs or otherwise retains the personnel that provide these services to us.

 

•

EPO reimburses EPCO for its services under the ASA in an amount equal to the sum of all costs and expenses incurred by EPCO which are directly and indirectly related to our business or activities (including expenses reasonably allocated to EPO by EPCO).

 

F-21

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•

EPO participates as a named insured in EPCO’s overall insurance program, which provides our operations with property damage, business interruption and other insurance coverage, the scope and amounts of which we believe are customary and prudent for the nature and extent of our operations. The associated premium expenses are reasonably allocated to us by EPO. See Note 9 for information regarding insurance risks.

Our operating costs and expenses include amounts paid to EPCO for the costs it incurs to operate our Business, including the compensation of EPCO’s employees. Likewise, our general and administrative costs include expenses reasonably allocated to us by EPO for administrative services provided by EPCO under the ASA, including the compensation of EPCO’s employees. In general, our reimbursement to EPO for administrative services is either (i) on an actual basis for direct expenses it incurs on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to the ASA based on the estimated use of such services by each party (e.g., the allocation of legal or accounting salaries based on estimates of time spent on each entity’s business and affairs). With respect to costs allocated to our businesses by EPO, we believe that such allocation is reasonable.

Privately held affiliates of EPCO lease office space to EPO and we are allocated a reasonable share of EPO’s overall cost based on our usage. The rental rates in these lease agreements approximate market rates.

Transactions with Unconsolidated Affiliates

Poseidon

We provide management, administrative and pipeline operator services to Poseidon under an Operation and Management Agreement (the “Poseidon OMA”). Currently, the Poseidon OMA renews automatically annually unless terminated by either party (as defined in the agreement). Our revenues for the three months ended June 30, 2015 and 2014 reflect $2.0 million and $1.9 million, respectively, of fees we earned through the provision of services under the Poseidon OMA. Likewise, our revenues for the six months ended June 30, 2015 and 2014 reflect $4.0 million and $3.8 million, respectively, of such fees.

We have space use rights on the SS-332B offshore platform owned by Cameron Highway. This platform is located adjacent to our SS-332A offshore platform. We sublease our space on SS-332B to Poseidon and also lease space on SS-332A to Poseidon. The term of these agreements extend until the platforms are abandoned. Our revenues for each of three months ended June 30, 2015 and 2014 reflect $0.1 million of fees we earned under these leasing arrangements. Likewise, our revenues for both of the six months ended June 30, 2015 and 2014 reflect $0.2 million of such fees.

Cameron Highway

We provide management, administrative and pipeline operator services to Cameron Highway under an Operation and Management Agreement (the “Cameron Highway OMA”). The Cameron Highway OMA renews automatically annually unless terminated by either party (as defined in the agreement). Our revenues for the three months ended June 30, 2015 and 2014 reflect $1.8 million and $1.6 million, respectively, of fees we earned through the provision of services under the Cameron Highway OMA. Likewise, our revenues for the six months ended June 30, 2015 and 2014 reflect $3.4 million and $3.2 million of such fees, respectively.

Cameron Highway also leases space on our Garden Banks 72 offshore platform. We received $0.2 million and $0.3 million in lease payments from Cameron Highway during the three months ended June 30, 2015 and 2014, respectively. Likewise, we received $0.4 million in lease payments from Cameron Highway during both the six months ended June 30, 2015 and 2014, respectively.

 

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We lease space on Cameron Highway’s SS-332B offshore platform. We paid less than $0.1 million in lease payments to Cameron Highway during each of the three months ended June 30, 2015 and 2014. Our lease payments to Cameron Highway during the six months ended June 30, 2015 and 2014 were less than $0.1 million in each period.

Deepwater Gateway

We provide technical and administrative services to Deepwater Gateway under a Management Services Agreement (the “Deepwater Gateway MSA”). The Deepwater Gateway MSA continues indefinitely until either party decides to exercise their termination rights (as defined in the agreement). Our revenues for the three months ended June 30, 2015 and 2014 reflect less than $0.1 million, respectively, of fees we earned through the provision of services under the Deepwater Gateway MSA. Likewise, our revenues for the six months ended June 30, 2015 and 2014 reflect less than $0.1 million of such fees, respectively.

SEKCO

We provide project and asset management, administrative and pipeline operator services to SEKCO under an Operating and Management Agreement (the “SEKCO OMA”). The SEKCO OMA began in July 2014 upon completion of the SEKCO Oil Pipeline. The SEKCO OMA continues indefinitely until either party decides to exercise their termination rights (as defined in the agreement). Our revenues for the three months ended June 30, 2015 reflect $0.1 million of fees we earned through the provision of services under the SEKCO OMA. Likewise, our revenues for the six months ended June 30, 2015 reflect $0.3 million of such fees.

Note 8. Commitments and Contingencies

Litigation

As part of our normal business activities, we may be named as defendants in legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully indemnify us against losses arising from future legal proceedings.

Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the possible need for accounting recognition and disclosure of any contingencies. We accrue an undiscounted liability for those contingencies where the loss is probable and the amount can be reasonably estimated. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum amount in the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our combined financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss.

Our evaluation of litigation contingencies is based on the facts and circumstances of each case and predicting the outcome of these matters involves uncertainties. In the event the assumptions we use to evaluate these matters change in future periods or new information becomes available, we may be required to establish reserves for litigation losses. In an effort to mitigate expenses associated with litigation, we may settle legal proceedings out of court.

 

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We do not have any current or pending litigation involving our offshore operations that is expected to have a material impact on our combined financial statements. Accordingly, we did not establish any reserves for litigation at June 30, 2015 or December 31, 2014.

Independence Hub Agreement

In November 2004, we entered into the Independence Hub Agreement (the “IHA”) with a group of producers (the “I-Hub Producers”) currently consisting of Anadarko, Marubeni Oil and Gas USA Inc., Statoil Gulf of Mexico LLC, Eni Petroleum Co. Inc. and Energy Resource Technology GOM, Inc. The I-Hub Producers committed to us for processing their natural gas production from certain oil and gas leases (life of lease production dedications) located in the Atwater Valley, DeSoto Canyon, Mississippi Canyon and Lloyd Ridge areas of the Gulf of Mexico.

In turn, we are required to reserve sufficient processing capacity, as detailed in the IHA, on the Independence Hub platform to handle such dedicated production. To the extent we have excess platform processing capacity (i.e., capacity not reserved by the I-Hub Producers), we may seek additional customers to utilize such spare capacity.

The I-Hub Producers pay their allocable share of all operating and maintenance costs of the platform based on throughput volumes. Such costs are paid directly to Anadarko, as operator of the platform.

Excluding force majeure situations, an I-Hub Producer may terminate its relationship with us under the IHA if we fail to process such producer’s production for 45 consecutive days, or 90 days in any 365-day period. If an I-Hub Producer relinquishes its dedicated leases, the IHA terminates with respect to that producer.

Contractual Obligations

HIOS has entered into a separation, dehydration and measurement services agreement with a third-party service provider. This agreement obligates HIOS to pay $0.2 million per month through the remainder of 2015. We have no other material contractual obligations.

Noncurrent Liabilities

The following table summarizes the components of “Noncurrent liabilities” as presented on our Unaudited Combined Balance Sheets at the dates indicated:

 

		June 30,				December 31,
		2015				2014
Long-term portion of asset retirement obligations (see Note 4)		$	94.2			$	94.6

Note 9. Significant Risks and Uncertainties

Nature of Operations in the Gulf of Mexico

We provide midstream energy services to producers in the Gulf of Mexico. Our services include the gathering, transporting, platform processing or otherwise handling of crude oil and natural gas volumes for customers. Demand for our services depends on crude oil and natural gas production volumes from the resource basins served by our assets. Changes in the prices of crude oil and natural gas may impact upstream production activities and downstream demand for hydrocarbon products. Production volumes may be negatively impacted by decreases in crude oil and natural gas prices to the extent that such price declines render the associated production wells uneconomic, which would result in production being shut-in. Changes in the prices of crude oil and natural gas may also impact demand for hydrocarbon products, which in turn may impact production volumes. Decreases in demand

 

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may be caused by a variety of factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition from other forms of energy, adverse weather conditions and government regulations affecting hydrocarbon prices and production levels.

Our offshore pipelines and platforms are directly impacted by producer exploration and production activities in the Gulf of Mexico for crude oil and natural gas. These reserves are depleting assets. Our pipeline systems must access additional reserves to offset either (i) the natural decline in production from existing connected wells and/or (ii) the loss of production to competing service providers. We actively seek to offset the loss of volumes due to depletion by adding connections to new customers and production fields.

Offshore exploration and production activities involve additional risks and different regulations than similar activities in onshore developments. Since the Deepwater Horizon (or Macondo) oil spill in the Gulf of Mexico during 2010, an event unrelated to our operations, the U.S. Department of Interior and state regulatory authorities have promulgated substantial additional regulations, including regulations related to the approval of new permits for offshore drilling, enhanced inspections of offshore oil and gas rigs and more stringent safety and accident preparedness plans. These new regulatory requirements have added, and may continue to add, delays in the permitting of offshore wells and costs in the planning, permitting, development and operation of new and existing wells by our customers. A decline in, or failure to achieve anticipated volumes of crude oil and natural gas supplies due to any of these factors could have a material adverse effect on our financial position, results of operations and cash flows. In addition, to the extent that new regulations or other governmental actions significantly increase the estimated future costs associated with our asset retirement obligations, it could have a material adverse effect on our financial position, results of operations or cash flows.

Our assets are located in the northern Gulf of Mexico primarily offshore Texas, Louisiana, Mississippi and Alabama and may suffer damage and resulting downtime due to tropical weather events such as hurricanes. If our assets, or those connected to our assets (e.g., a downstream pipeline or platform), were to experience significant weather-related losses and downtime, it could have a material impact on our financial position, results of operations and cash flows. See “Insurance Risks” below.

Insurance Risks

Under the EPCO ASA (see Note 7), EPO participates as a named insured in EPCO’s overall insurance program, which provides our operations with property damage, business interruption and other insurance coverage, the scope and amounts of which we believe are customary and prudent for the nature and extent of our offshore operations. While we believe EPCO maintains adequate insurance coverage on behalf of EPO, insurance may not fully cover every type of damage, interruption or other loss that might occur. If our offshore operations were to incur a significant loss for which EPO was not fully insured, it could have a material impact on our combined financial position, results of operations and cash flows.

In addition, there may be timing differences between amounts we recognize related to property damage costs, amounts we are required to pay in connection with a loss, and amounts we subsequently receive from insurance carriers as reimbursements. Any event that materially interrupts the revenues generated by our combined operations, or other losses that require us to make material expenditures not reimbursed by insurance, could reduce our ability to pay distributions to our owners.

Involuntary conversions result from the loss of an asset due to some unforeseen event (e.g., destruction due to an explosion and fire or named windstorm). Certain of these events are covered by insurance, thus resulting in a property damage insurance recovery. Amounts we receive from insurance carriers are net of any deductibles related

 

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to the covered event. We record a receivable from insurance to the extent we recognize a loss from an involuntary conversion event and the likelihood of our recovering such loss is deemed probable. To the extent that any of our insurance claim receivables are later judged not probable of recovery (e.g., due to new information), such amounts are immediately expensed. We recognize gains on involuntary conversions when the amount received from insurance exceeds the net book value of the retired asset(s).

In addition, we do not recognize gains related to insurance recoveries until all contingencies related to such proceeds have been resolved, that is, a non-refundable cash payment is received from the insurance carrier or we have a binding settlement agreement with the carrier that clearly states that a non-refundable payment will be made. To the extent that an asset is rebuilt, the associated expenditures are capitalized, as appropriate, on our Unaudited Combined Balance Sheets and presented as capital expenditures on our Unaudited Statements of Combined Cash Flows.

Currently, EPCO’s deductible for non-windstorm related property damage claims involving our offshore assets is $5.0 million. We continue to maintain business interruption coverage for our offshore assets, except for those situations involving windstorm-related downtime. Due to the high cost of windstorm insurance coverage for our offshore Gulf of Mexico assets, we elected to self-insure these assets beginning in June 2013. We have continued to self-insure these assets for the annual policy period ending in May 2016.

Although EPCO’s current insurance program does not provide any windstorm coverage for our offshore assets, producers affiliated with our Independence Hub and Marco Polo platforms continue to provide certain levels of physical damage windstorm coverage for each of these offshore assets. The Independence Hub and Marco Polo producers agreed to provide us with $545 million and $392 million, respectively, of aggregate insurance coverage for named windstorm events through May 2015. With respect to the policy period beginning in June 2015, we expect the Independence Hub and Marco Polo producers to provide us with $545 million and $542 million, respectively, of aggregate insurance coverage for named windstorm events through May 2016.

 

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