Exhibit 99.1

Poseidon Oil Pipeline Company, L.L.C.

Index to Financial Statements

Poseidon Oil Pipeline Company, L.L.C.

Unaudited Balance Sheets

(in thousands of dollars)

The accompanying notes are an integral part of these financial statements.

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Poseidon Oil Pipeline Company, L.L.C.

Unaudited Statements of Operations

(in thousands of dollars)

The accompanying notes are an integral part of these financial statements.

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Poseidon Oil Pipeline Company, L.L.C.

Unaudited Statements of Cash Flows

(in thousands of dollars)

The accompanying notes are an integral part of these financial statements.

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Poseidon Oil Pipeline Company, L.L.C.

Unaudited Statements of Members’ Equity

(in thousands of dollars)

The accompanying notes are an integral part of these financial statements.

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Poseidon Oil Pipeline Company, L.L.C.

Notes to Unaudited Financial Statements

Company Organization

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. Unless the context requires otherwise, references to “we”, “us”, “our” or “the Company” within these notes are intended to mean Poseidon.

At June 30, 2015 we were owned (i) 36% by Poseidon Pipeline Company, L.L.C. (“Enterprise”), (ii) 36% by Equilon Enterprises LLC (d/b/a Shell Oil Products U.S., “Shell”) and (iii) 28% by GEL Poseidon, LLC (“Genesis”). Enterprise, Shell and Genesis are referred to individually as a “Member,” or collectively as the “Members.” On July 1, 2015, Shell contributed its ownership interest in Poseidon to Shell Midstream Partners, L.P. On July 24, 2015, the ownership interest held by Enterprise was transferred to Genesis as a part of the sale of Enterprise Products Partners, L.P.’s sale of its offshore business.

Description of Business

The Poseidon Oil Pipeline System (the “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 system extends 366 miles and has an approximate capacity of 430 thousand barrels per day. The system includes a pipeline junction platform located at South Marsh Island 205 (“SMI-205”). Manta Ray Gathering Company, L.L.C. (“Manta Ray”), an affiliate of Enterprise, serves as operator of the Pipeline.

See Note 3 for information regarding major capital projects completed in 2014.

Our financial statements are prepared on the accrual basis of accounting in accordance with U.S. generally accepted accounting principles (“GAAP”).

Except as noted within the context of each footnote disclosure, dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

In preparing these financial statements, the Company has evaluated subsequent events for potential recognition or disclosure through November 2, 2015, the issuance date of the financial statements.

Basis of Presentation

Our results of operations for the three and six months ended June 30, 2015 are not necessarily indicative of results expected for the full year of 2015. In our opinion, the accompanying unaudited financial statements as of June 30, 2015 and for the three and six months ended June 30, 2015 include all adjustments consisting of normal recurring accruals necessary for fair presentation.

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Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand 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 the financial statements are issued, which may result in a loss to the Company but which will only be resolved when one or more future events occur or fail to occur. The Company’s management and its legal counsel assess such contingent liabilities, and such assessment inherently involves an exercise of judgment. In assessing loss contingencies related to legal proceedings that are pending against the Company or unasserted claims that may result in such proceedings, the Company’s legal counsel evaluates the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of 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 and the nature of the contingent liability would be disclosed in the Company’s 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 or recorded unless they involve guarantees that are material to the Company, in which case the nature of the guarantee would be disclosed.

We had no matters requiring loss contingency accruals or disclosure at December 31, 2014 or June 30, 2015.

Crude Oil Handling Costs

Crude oil handling costs represent (i) expenses we incur as a result of utilizing third party-owned pipelines in the provision of services and (ii) quality bank expenses we record as a result of selling common stream crude oil to producers. Quality bank charges are incurred when the crude oil we sell back to producers is of a lesser quality than the crude oil we originally purchased from the producer.

Environmental Costs

Our operations are subject to extensive federal environmental regulations. 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. There were no environmental remediation liabilities incurred as of June 30, 2015 or December 31, 2014.

Estimates

Preparing our financial statements in conformity with GAAP requires us to make estimates that affect amounts presented in the financial statements. Our most significant estimates relate to (i) the useful lives and depreciation methods used for fixed assets; (ii) measurement of fair value and projections used in impairment testing of fixed assets; (iii) contingencies; and (iv) revenue and expense accruals.

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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 financial statements.

Fair Value Information

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair values based on their short-term nature.

Impairment Testing for Long-Lived Assets

Long-lived assets such as 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 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. No asset impairment charges were recognized during the three and six months ended June 30, 2015 or 2014.

Income Taxes

We are organized as a pass-through entity for federal income tax purposes. As a result, our financial statements do not provide for such taxes and our Members are individually responsible for their allocable share of our taxable income for federal income tax purposes.

Inventories

We take title to crude oil volumes we purchase from producers and volumes we obtain through contractual pipeline loss allowances. Timing and measurement differences between receipt and delivery volumes, as well as fluctuations in crude oil pricing, impact our inventory balances. Our inventory amounts are presented at the lower of average cost or market.

Due to fluctuating crude oil prices, we recognize lower of cost or market adjustments when the carrying value of our crude oil inventory exceeds its net realizable value. These non-cash charges are a component of “Crude oil handling costs” on our Unaudited Statements of Operations in the period they are recognized. We recognized $0.1million of lower of cost or market adjustments for the three and six months ended June 30, 2015. There were $0.1 million of lower of cost or market adjustments for the six months ended June 30, 2014. These adjustments during the three months ended June 30, 2014 were immaterial.

Property, Plant and Equipment

Property, plant and equipment is recorded at 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 reporting periods it benefits. Our property, plant and equipment is depreciated using the straight-line method,

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which results in depreciation expense being incurred evenly over the life of an asset. Our estimate of depreciation expense incorporates management assumptions regarding the useful economic lives and residual values of our assets.

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 long-lived asset. ARO amounts are measured at their estimated fair value using expected present value techniques. Over time, the liability is accreted to its present value (through accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-term asset. We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts. See Note 3 for additional information regarding our property, plant and equipment and related AROs.

Revenue Recognition

Crude oil handling revenues are generated from purchase and sale agreements whereby we purchase crude oil from producers at various receipt points along the Pipeline for a contractual fixed price (less a “handling fee”) and sell common stream crude oil back to the producers at various redelivery points at the same contractual fixed price (before the handling fee was applied). Since these purchase and sale transactions are with the same customer and entered into in contemplation of one another, the purchase and sales amounts are netted against one another and the residual handling fees are recognized as crude oil handling revenue. The intent of these buy-sell arrangements is to earn a fee for handling crude oil (a service to the producer) and not to engage in crude oil marketing activities. We also net the corresponding receivables and payables from such transactions on our Balance Sheets for consistency of presentation.

We have 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. The amount of pipeline capacity reserved each year for the Lucius producers is based on their expected production volumes for that period (as defined in the contract). The capacity reservation agreements require the Lucius producers to make scheduled minimum bill payments to us (as defined in the contract). We defer that portion of the minimum bill payments that relate to future performance obligations under the contract. We recognized $3.3 million and $6.5 million of pipeline capacity reservation revenues from the Lucius producers during the three and six months ended June 30, 2015, respectively. At December 31, 2014 and June 30, 2015, our deferred revenue attributable to the Lucius agreements totaled $6.0 million and $11.7 million, respectively.

Our agreements with the Lucius producers also provide for fees on volumes handled on our Pipeline. With the inception of Lucius production flows in January 2015, we began billing these amounts. Amounts billed for the six months ended June 30, 2015 were $7.7 million.

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Our property, plant and equipment values and accumulated depreciation balances were as follows at the dates indicated:

In September 2014, we completed modifications to our SMI-205 platform and equipment we own on the Ship Shoal 332A (“SS-332A”) platform owned by Manta Ray. These modifications were made in connection with an affiliate pipeline project, which delivers crude oil volumes to us from the Lucius production field located in the Southeast Keathley Canyon area of the deepwater Gulf of Mexico. The affiliate pipeline project was completed in July 2014, with first production flows from the Lucius producers in January 2015.

Depreciation expense was $3.9 million and $2.9 million for the three months ended June 30, 2015 and 2014. For the six months ended June 30, 2015 and 2014, depreciation expense was $7.8 million and $5.7 million, respectively.

Asset Retirement Obligations

Our AROs result from regulatory requirements that would be triggered by the retirement of our offshore pipeline and platform assets. The following table presents information regarding our estimable asset retirement liabilities for the periods noted.

Certain segments of our pipeline system were constructed under permits issued by the U.S. Army Corps of Engineers (the “CoE”). These permits generally require that, upon abandonment of a pipeline segment, we restore the location to its pre-existing condition. Historically, the CoE has allowed pipeline owners to abandon a pipeline segment in-place; however, in a June 2015 letter to the owner of a natural gas gathering system located in the state waters of Texas, the CoE requested that the pipeline operator fully remove the pipelines from the Gulf of Mexico in accordance with its permits. In light of this recent development, the CoE might require us to fully remove any pipeline segments that we abandon (that are within the CoE’s jurisdiction) rather than abandon them in place. Given that we are uncertain as to how the CoE would respond to any abandonment request we might make in the distant future, we are not able to estimate the amount of incremental asset retirement costs that we could incur if the CoE required the full removal of any of our pipeline segments under its jurisdiction. Accordingly, we have not made any provision for such matters in our financial statements.

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Property, plant and equipment at both June 30, 2015 and December 31, 2014 includes $0.2 million of asset retirement costs that were capitalized as an increase in the associated long-lived asset.

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

We report in one business segment, Offshore Crude Oil Pipelines, which consists of providing crude oil handling services to producers in the developments that we serve. The following table summarizes our financial information with respect to this business segment:

Handling fees began declining in mid-2014 primarily due to discontinuation of the Auger strategy in anticipation of first flows from the Lucius producers.

Capacity reservation fees have increased as a result of our long-term agreements with the Lucius producers (see Note 2) as well as a one-year agreement with another producer.

April 2011 Credit Facility

In April 2011, we entered into a revolving bank credit facility that had an initial borrowing capacity of $125 million, which was increased over time to $225 million. The weighted-average variable interest rate charged under the April 2011 credit facility was approximately 2.3% during the year ended December 31, 2014. From January 1, 2015 through the date of its termination, the weighted-average variable interest rate charged under the April 2011 credit facility was approximately 2.3%. In addition, we paid commitment fees on the unused portion of the revolving credit facility at rates that varied from 0.25% to 0.375%.

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The April 2011 credit facility included customary financial covenants that, if breached, would have accelerated the maturity date of the debt. We were in compliance with these financial covenants at December 31, 2014.

The April 2011 credit facility was set to mature in April 2015; however, the facility was terminated in February 2015 and its outstanding principal balance of $186.8 million was refinanced under the new February 2015 credit facility (see below).

February 2015 Credit Facility

In February 2015, we entered into an amended and restated revolving credit agreement having an initial borrowing capacity of $225 million, with a provision that its borrowing capacity could be expanded to $275 million with additional commitments from the lenders. Amounts borrowed under the February 2015 credit facility mature in February 2020. We used $186.8 million of borrowing capacity under the new credit facility to refinance principal amounts that were outstanding under the April 2011 credit facility at termination. We incurred $1.3 million of debt issuance costs related to the February 2015 Credit Facility of which $0.3 million is deferred within current assets and $1.0 million is deferred within other assets on our Unaudited Balance Sheet at June 30, 2015.

The weighted-average variable interest rate charged under the February 2015 credit facility was approximately 2.2% from its inception through June 30, 2015. Interest rates charged under the 2015 credit facility are dependent on certain quarterly financial ratios (as defined in the credit agreement). For Eurodollar loans where our leverage ratio is greater than or equal to 1:1 and less than 2:1, the interest rate is the London Interbank Offered Rate (“LIBOR”) plus 1.75%, and for Base Rate loans (as defined in the credit agreement), the interest rate is 0.75% plus a variable base rate equal to the greater of (i) the prime rate, (ii) the federal funds rate plus 0.50% or (iii) LIBOR plus 1.00%. The interest rate on Eurodollar and Base Rate loans would increase by 0.25% if our leverage ratio increased to greater than 2:1 and would decrease by 0.25% if our leverage ratio decreased to less than or equal to 1:1. In addition, we pay commitment fees on the unused portion of the revolving credit facility at rates that vary from 0.25% to 0.375%.

The February 2015 credit facility is non-recourse to our Members and secured by our assets. The February 2015 credit facility also contains customary covenants such as restrictions on debt levels, liens, guarantees, mergers, sale of assets and distributions to Members. A breach of any of these covenants could result in acceleration of our debt financial obligations. We were in compliance with the covenants of our credit facility at June 30, 2015.

In general, if an Event of Loss occurs (as defined in the credit agreement), we are obligated to either repair the damage or use any insurance proceeds we receive to reduce debt principal outstanding.

As a limited liability company, our Members are not personally liable for any of our debts, obligations or other liabilities. Income or loss amounts are allocated to Members based on their respective membership interests. Cash contributions by and distributions to Members are also based on their respective membership interests.

Cash distributions to Members are determined by our Management Committee, which is responsible for conducting the Company’s affairs in accordance with our limited liability agreement.

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

Other operating costs and expenses include amounts charged to us by Manta Ray for operator fees and space on their SS-332A platform.

The following table summarizes our related party accounts receivable and accounts payable amounts at the dates indicated:

Regulatory and Legal

As part of our normal business activities, we are subject to various laws and regulations, including those related to environmental matters. In the opinion of management, compliance with existing laws and regulations will not materially affect our financial position, results of operations or cash flows.

Also, in the normal course of business, we may be a party to lawsuits and similar proceedings before various courts and governmental agencies involving, for example, contractual disputes, environmental issues and other matters. We are not aware of any such matters at June 30, 2015 or December 31, 2014. If new information becomes available, we will establish accruals and/or make disclosures as appropriate.

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Other Commitments

At June 30, 2015, short-term payment obligations relating to capital expenditures, which represent unconditional payment obligations to vendors for products to be delivered in connection with capital projects, were immaterial.

Production and Credit Risk due to Customer Concentration

Offshore pipeline systems such as ours are directly impacted by exploration and production activities in the Gulf of Mexico for crude oil. Crude oil reserves are depleting assets. Our crude oil pipeline system must access additional reserves to offset either (i) the natural decline in production from existing connected wells or (ii) the loss of production to a competing takeaway pipeline. We actively seek to offset the loss of volumes due to depletion by adding connections to new customers and production fields.

Regulatory Risk

To the extent that new regulations or other governmental actions significantly curtail the exploration and production activities of Gulf of Mexico producers connected to our Pipeline or 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.

Insurance Risks

Our assets are located offshore Louisiana in the Gulf of Mexico, which is prone to tropical weather events such as hurricanes. Our Members are required to maintain certain levels of insurance with respect to our assets (excluding windstorm coverage). If our assets were significantly damaged in a storm, it could have a material impact on our financial position, results of operations and cash flows.

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