UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2015

OR

☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from   to

Commission file number 001-36647

JP ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

600 East Las Colinas Blvd
Suite 2000

Irving, Texas 75039
(Address of principal executive offices) (Zip Code)

(Registrant’s telephone number, including area code):  (972) 444-0300

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  YES ☒   NO ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  YES ☒   NO ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES ☐   NO ☒

At November 6, 2015, there were 18,464,101 common units and 18,128,640 subordinated units outstanding. 

TABLE OF CONTENTS

PART IFINANCIAL INFORMATION

Unless the context otherwise requires, references in this Quarterly Report on Form 10-Q (this “report” or this “Form 10-Q”) to “JP Energy Partners,” “the Partnership,” “we,” “our,” “us,” or like terms refer to JP Energy Partners LP and its subsidiaries, and references to “our general partner” refer to JP Energy GP II LLC, our general partner.  References to “our sponsor” or “Lonestar” refer to Lonestar Midstream Holdings, LLC, which, together with JP Energy GP LLC, CB Capital Holdings II, LLC and the Greg Alan Arnold Separate Property Trust, entities owned by certain members of our management, owns and controls our general partner. References to “ArcLight Capital” refer to ArcLight Capital Partners, LLC and references to “ArcLight Fund V” refer to ArcLight Energy Partners Fund V, L.P. References to “ArcLight” refer collectively to ArcLight Capital and ArcLight Fund V. ArcLight Capital manages ArcLight Fund V, which controls our general partner through its ownership and control of Lonestar.

Forward-Looking Statements

Certain statements and information in this Form 10-Q may constitute “forward-looking statements.”  The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature.  These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us.  While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate.  All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions.  Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections.  Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

the price of, and the demand for, crude oil, refined products and natural gas liquids (“NGLs”) in the markets we serve;

the volumes of, and margin on, crude oil that we gather, transport and store, the throughput volumes at our refined products terminals and our NGL sales volumes and margins;

the fees we receive for the crude oil, refined products and NGL volumes we handle;

pressures from our competitors, some of which may have significantly greater resources than us;

the cost of propane that we buy for resale, including due to disruptions in its supply, and whether we are able to pass along cost increases to our customers;

competitive pressures from other energy sources such as natural gas, which could reduce existing demand for propane;

the risk of contract cancellation, non-renewal or failure to perform by our customers, and our inability to replace such contracts and/or customers;

leaks or releases of hydrocarbons into the environment that result in significant costs and liabilities;

the level of our operating, maintenance and general and administrative expenses;

regulatory action affecting our existing contracts, our operating costs or our operating flexibility;

failure to secure or maintain contracts with our largest customers, or non-performance of any of those customers under the applicable contract;

competitive conditions in our industry;

changes in the long-term supply of and demand for oil, NGLs and natural gas;

the availability and cost of capital and our ability to access certain capital sources;

a deterioration of the credit and capital markets;

volatility of fuel prices;

actions taken by our customers, competitors and third-party operators;

our ability to complete growth projects on time and on budget;

inclement or hazardous weather conditions, including flooding, and the physical impacts of climate change;

environmental hazards;

industrial accidents;

changes in laws and regulations (or the interpretation thereof) related to the transportation, storage or terminaling of crude oil and refined products or the distribution and sales of NGLs;

fires, explosions or other accidents;

the effects of future litigation; and

other factors discussed elsewhere in this Form 10-Q and in our other current and periodic reports filed with the Securities and Exchange Commission (the “SEC”).

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.  We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

Item 1.Financial Statements

JP ENERGY PARTNERS LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

JP ENERGY PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

JP ENERGY PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

JP ENERGY PARTNERS LP

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

JP ENERGY PARTNERS LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Business and Basis of Presentation

Business.  The unaudited condensed consolidated financial statements presented herein contain the results of JP Energy Partners LP, a Delaware limited partnership, and its subsidiaries. All references to the “Partnership”, “JPE”, “us”, “we”, “our”, and all similar expressions are references to JP Energy Partners LP and our consolidated, wholly owned subsidiaries, unless otherwise expressly stated or the context requires otherwise.  We were formed in May 2010 by members of management and were further capitalized by ArcLight Capital Partners, LLC (“ArcLight”) to own, operate, develop and acquire a diversified portfolio of midstream energy assets. Our operations currently consist of: (i) crude oil pipelines and storage; (ii) crude oil supply and logistics; (iii) refined products terminals and storage; and (iv) natural gas liquid (“NGL”) distribution and sales, which together provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs in the United States.  JP Energy GP II LLC (“GP II” or our “general partner”) is our  general partner.

Initial Public Offering.  On October 7, 2014, we completed our initial public offering (“IPO”) of 13,750,000 common units representing a 37.7%  limited partner interest in us.    In connection with the IPO, we entered into a Third Amended and Restated Agreement of Limited Partnership (the “Amended Partnership Agreement”) on October 7, 2014. The Amended Partnership Agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2014, we distribute all of our available cash (as defined in our Amended Partnership Agreement) to unitholders of record on the applicable record date, subject to certain terms and conditions.

Common Control Acquisition between JPE and JP Development.  On July 12, 2012, ArcLight and the owners of JPE formed JP Energy Development LP, a Delaware limited partnership (“JP Development”), for the purpose of supporting JPE’s growth. JPE and JP Development are under common control because a majority of the equity interests in each entity and their general partners are owned by ArcLight. On February 12, 2014, pursuant to a Membership Interest and Asset Purchase Agreement, we acquired certain midstream assets (the “Dropdown Assets”) from JP Development for an aggregate purchase price of approximately $319.1 million (the “Common Control Acquisition”), which was comprised of 12,561,934 JPE Class A Common Units and $52.0 million in cash. We financed the cash portion of the purchase price through borrowings under our revolving credit facility.  The total purchase price for the Common Control Acquisition exceeded the book value of the assets acquired. As a result, the excess of the total purchase price over the book value of the assets acquired of $12.7 million was considered a deemed distribution by our general partner.

Basis of Presentation.  Because JPE and JP Development are under common control, we are required under generally accepted accounting principles in the United States (“GAAP”) to account for the Common Control Acquisition in a manner similar to the pooling of interests method of accounting. Under this method of accounting, our balance sheet reflects JP Development’s historical carryover net basis in the Dropdown Assets instead of reflecting the fair market value of assets and liabilities of the Dropdown Assets. We also retrospectively recast our financial statements to include the operating results of the Dropdown Assets from the dates these assets were originally acquired by JP Development (the dates upon which common control began). Our recast historical consolidated financial statements include all revenues, costs, expenses, assets and liabilities directly attributable to the Dropdown Assets, as well as allocations that include certain expenses for services, including, but not limited to, general corporate expenses related to finance, legal, information technology, shared services, employee benefits and incentives and insurance. These expenses have been allocated based on the most relevant allocation method to the services provided, primarily on the relative percentage of revenue, relative percentage of headcount, or specific identification. Management believes the assumptions underlying the combined financial statements are reasonable. However, the combined financial statements, which include the Dropdown Assets, do not fully reflect what our balance sheet, results of operations and cash flows would have been, had the Dropdown Assets been under JPE management during the periods presented. As a result, historical financial information is not necessarily indicative of what our balance sheet, results of operations and cash flows will be in the future.

JP Development has a centralized cash management that covers all of its subsidiaries. The net amounts due from or to JP Development by the Dropdown Assets relate to a variety of intercompany transactions including the collection of trade receivables, payment of accounts payable and accrued liabilities, charges of allocated corporate expenses and payments by JP Development on behalf of the Dropdown Assets. Such amounts have been treated as deemed contributions from or deemed distributions to JP Development for the nine months ended September 30, 2014. The total net effect of the deemed contributions is reflected as contribution from the predecessor in the statements of cash flows as a financing activity. The net balances due to us from the Dropdown Assets were settled in cash based on the outstanding balances at the effective date of the Common Control Acquisition.

The results of operations for the three and nine months ended September 30, 2015 and 2014 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for fair statement of the financial position and results of operations for such interim periods in accordance with GAAP. Although we believe the disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC. These unaudited condensed consolidated interim financial statements and the notes thereto should be read in conjunction with our audited consolidated financial statements and the related notes for the year ended December 31, 2014 included in our Annual Report on Form 10-K filed with the SEC on March 11, 2015.

2. Summary of Significant Accounting Policies

Principles of Consolidation. Our unaudited condensed consolidated financial statements have been prepared in accordance with GAAP for interim financial information. All intercompany accounts and transactions have been eliminated in the preparation of the accompanying unaudited condensed consolidated financial statements.

Reclassification.  Certain previously reported amounts have been reclassified to conform to the current year presentation. For the three and nine months ended September 30, 2014, we reclassified $2,559,000 and $7,151,000, respectively, from gathering, transportation and storage fees to crude oil sales to conform to the current year presentation.

Use of Estimates.  The unaudited condensed consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the condensed consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.

Fair value measurement.  We utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. We determine fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels:

Level 1 Inputs—Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date.

Level 2 Inputs—Other than quoted prices included in Level 1 inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3 Inputs—Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at measurement date.

The fair value of our derivatives (see Note 8) was estimated using industry standard valuation models using market-based observable inputs, including commodity pricing and interest rate curves (Level 2). The fair value of our contingent liabilities (see Note 5) was determined using the discounted future estimated cash payments based on inputs that are not observable in the market (Level 3). We do not have any other assets or liabilities measured at fair value on a recurring basis.

Our other financial instruments consist primarily of cash and cash equivalents and long-term debt. The fair value of long-term debt approximates the carrying value as the underlying instruments are at rates similar to current rates offered to us for debt with the same remaining maturities.

Restricted Cash. Restricted cash consists of cash balances that are restricted as to withdrawal or usage and include cash to secure crude oil production taxes payable to the applicable taxing authorities.

Accounts Receivable.  Accounts receivable are reported net of the allowance for doubtful accounts. The allowance for doubtful accounts is based on specific identification and expectation of collecting considering historical collection results. Account balances considered to be uncollectible are recorded to the allowance for doubtful accounts and charged to bad debt expense, which is included in general and administrative expenses in the condensed consolidated statements of operations. The allowance for doubtful accounts was $1,806,000 and $1,134,000 as of September 30, 2015 and December 31, 2014, respectively.

Revenue Recognition. We recognize revenue when persuasive evidence of an arrangement exists, delivery has occurred and/or services have been rendered, the seller’s price to the buyer is fixed and determinable and collectability is reasonably assured. 

Revenue-related taxes collected from customers and remitted to taxing authorities, principally sales taxes, are presented on a net basis within the consolidated statements of operations.

Crude Oil Pipelines and Storage. The crude oil pipelines and storage segment mainly generates revenues through crude oil sales and pipeline transportation and storage fees. Crude oil sales revenues are generated through outright purchase and sale contracts as well as crude oil pipeline transportation arrangements. Revenues for crude oil pipeline transportation services are recognized upon delivery of the product, and when payment has either been received or collection is reasonably assured. Our crude oil pipeline transportation arrangements are structured such that we purchase crude oil from a producer or supplier at a designated receipt point at an index price less a transportation fee, and sell at a designated delivery point, thereby locking in an amount that is, in effect, economically equivalent to a transportation fee. Any transportation costs we incur are included in the price of the product sold to customers, and are included within crude oil sales revenues and cost of sales, excluding depreciation and amortization. For our crude oil pipeline transportation arrangements, we enter into purchase and sale contracts with the same counterparty or different counterparties. In each case, we assess the indicators associated with agent and principal considerations for the arrangement to determine whether revenue should be recorded on a gross basis versus net basis.

Crude Oil Supply and Logistics. The crude oil supply and logistics segment mainly generates revenues through crude oil sales. We enter into outright purchase and sales contracts as well as buy/sell contracts with counterparties, under which contracts we gather, transport and blend different types of crude oil and eventually sell the blended crude oil to either the same counterparty or different counterparties. We account for such revenue arrangements on a gross basis. Occasionally, we enter into crude oil inventory exchange arrangements with the same counterparty which the purchase and sale of inventory are considered in contemplation of each other. Revenues from such inventory exchange arrangements are recorded on a net basis. In addition, we also provide crude oil transportation services to third party customers.

Refined Products Terminals and Storage. We generate fee-based revenues for terminal and storage services with longstanding customers under contracts that, consistent with industry practice, typically contain evergreen provisions after an initial term of six months to two years. Such fee-based revenues are recognized when services are provided upon delivery of the products to customers. Revenues are also generated by selling excess refined products that result from blending, additization and inventory control processes.

NGL Distribution and Sales. Revenues from the NGL distribution and sales segment are mainly generated from NGL and refined product sales, sales of the related parts and equipment and through gathering and transportation fees.

Comprehensive Loss. For the three and nine months ended September 30, 2015 and 2014, comprehensive loss was equal to net loss.

Recent Accounting Pronouncements.

In September 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-16, Business Combinations (Topic 805). ASU 2015-16 changes how the acquirer recognizes adjustments to the provisional amounts of a business combination that are identified during the measurement period  from a retrospective application of all affected financial periods to be recorded in the reporting period in which the adjustment amounts are determined. Additionally, the company needs to disclose, of the amounts recorded in current periods, what amounts would have been reported in previous periods if the adjustments had been recognized at the acquisition date.  ASU 2015-16 is effective for interim and annual periods beginning after December 15, 2015.  Early adoption of this ASU is permitted. The adoption of ASU 2015-16 is not expected to have a material impact on our consolidated financial statements and related disclosures.

In August 2015, the FASB issued ASU No. 2015-15, Interest—Imputation of Interest (Subtopic 835-30). ASU 2015-15 provides SEC Staff guidance to ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Cost as it relates to debt issuance cost associated with line-of-credit arrangements. The SEC staff recognized that ASU 2015-03 did not address presentation or subsequent measurement of debt issuances cost related to line-of-credit arrangements and noted that the SEC Staff wouldn’t object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratable over the term of the line-of-credit arrangement regardless of whether there are any outstanding borrowings of the line-of credit arrangement.  The adoption of ASU 2015-15 is not expected to have a material impact on our consolidated financial statements and related disclosures.

In July 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory. ASU 2015-11 changes the measurement principle for inventory measured using any method other than LIFO or the retail inventory method from the lower of cost or market to lower of cost and net realizable value.  Net realizable value is defined as estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation.  ASU 2015-11 is effective for interim and annual periods beginning after December 15, 2016.  Early adoption of this ASU is permitted.  We are currently evaluating the potential impact this standard will have on our consolidated financial statements and related disclosures.

In April 2015, the FASB issued ASU No. 2015-06, Earnings per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions.  ASU 2015-06 provides guidance on calculating and reporting historical earnings per unit under the two-class method following dropdown transactions between entities under common control. Under ASU 2015-06, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. Additionally, the previously reported earnings per unit of the limited partners for periods before the date of the dropdown transaction would not change as a result of the dropdown transaction. ASU 2015-06 is effective for interim and annual periods beginning after December 15, 2015, and should be applied retrospectively for all financial statements presented. Early adoption of this ASU is permitted. We adopted ASU 2015-06 in the second quarter of 2015 and the adoption did not have a material impact on our consolidated financial statements and related disclosures.

In April 2015, the FASB issued ASU No. 2015-03, Simplifying the Presentation of Debt Issuance Cost. ASU 2015-03 changes the requirements for presenting debt issuance costs and requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this amendment. ASU 2015-03 is effective for interim and annual periods beginning after December 15,

2015, with early adoption permitted. We adopted ASU 2015-03 in the third quarter of 2015 and the adoption did not have a material impact on our consolidated financial statements and related disclosures.

In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. ASU 2015-02 provides amended guidance on the consolidation evaluation for reporting entities that are required to evaluate whether they should consolidate certain legal entities, including limited partnerships. ASU 2015-02 is effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted. The adoption of ASU 2015-02 is not expected to have a material impact on our consolidated financial statements and related disclosures.

In June 2014, the FASB issued ASU No. 2014-12, Compensation - Stock Compensation, Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. ASU 2014-12 provides explicit guidance on accounting for share-based payments requiring a specific performance target to be achieved in order for employees to become eligible to vest in the awards when that performance target may be achieved after the requisite service period for the award. The ASU requires that such performance targets be treated as a performance condition, and should not be reflected in the estimate of the grant-date fair value of the award. Instead, compensation cost should be recognized in the period in which it becomes probable the performance target will be achieved. ASU 2014-12 is effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted. The adoption of ASU 2014-12 is not expected to have a material impact on our consolidated financial statements and related disclosures.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. ASU 2014-09 supersedes the existing revenue recognition guidance under GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing GAAP. ASU 2014-09 is effective for interim and annual periods beginning after December 15, 2016 using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). In August 2015, the FASB issued ASU No. 2015-14, Update Revenue from Contracts with Customers (Topic 606), which defers the effective date of ASU 2014-09 for public and non-public entities reporting under U.S. GAAP for one year. The FASB also decided to permit entities to early adopt the standard but adoption is not permitted earlier than the original effective date for public entities. We are currently evaluating the potential impact this standard will have on our consolidated financial statements and related disclosures.

3. Discontinued Operations

On June 30, 2014, we entered into and simultaneously closed an asset purchase agreement pursuant to which we sold all of our trucking and related assets and activities in North Dakota, Montana and Wyoming (the “Bakken Business”) for a purchase price of $9,100,000.  

The results of operations for the Bakken Business are presented as discontinued operations for all periods in the condensed consolidated statements of operations. Prior to the classification as discontinued operations, we reported the Bakken Business in our crude oil supply and logistics segment. The following table summarizes selected financial information related to the Bakken Business’s operations for the three and nine months ended September 30, 2014.

4. Net Income per Unit

Net income per unit applicable to limited partner common units and to limited partner subordinated units is computed by dividing the respective limited partners’ interest in net income for the period subsequent to the IPO by the weighted-average number of common units and subordinated units outstanding for the period. Income per limited partner unit is calculated in accordance with the two-class method for determining income per unit for master limited partnerships (“MLPs”) when incentive distribution rights (“IDRs”) and other participating securities are present. The two-class method requires that income per limited partner unit be calculated as if all earnings for the period were distributed as cash, and allocated by applying the provisions of the partnership agreement, and requires a separate calculation for each quarter and year-to-date period. Under the two-class method, any excess of distributions declared over net income is allocated to the partners based on their respective sharing of income specified in the partnership agreement. Diluted net income per unit includes the effects of potentially dilutive units on our common units, consisting of unvested phantom units. Basic and diluted net income per unit applicable to limited partners holding subordinated units are the same because there are no potentially dilutive subordinated units outstanding.  For the three and nine months ended September 30, 2015, dilutive loss per unit was equal to basic loss per unit because all instruments were antidilutive.

On October 23, 2015, the Board of Directors of our general partner declared a cash distribution for the third quarter of 2015 of $0.325 per common unit and subordinated unit. The distribution will be paid on November 13, 2015 to unitholders of record as of November 6, 2015.

The following data show securities that could potentially dilute earnings per unit in the future that were not included in the computation of diluted earnings per unit because to do so would have been antidilutive for the periods presented:

5. Acquisitions and Dispositions

Acquisition of Southern Propane Inc. On May 8, 2015, we acquired substantially all of the assets of Southern Propane Inc. (“Southern”), a Houston-based industrial and commercial propane distribution and logistics company. The acquisition expanded the asset base and market share of our NGL distribution and sales segment, specifically the acceleration of our entry into the Houston, Texas market as well as expansion of our industrial, non-seasonal customers. The total purchase price of $16,292,000 consisted of a $12,475,000 cash payment that was paid on the acquisition date, which was funded through the use of borrowings from our revolving credit facility, a $108,000 cash payment to the seller as the final working capital adjustment, the issuance of 266,951 common units valued at $3,442,000 and a contingent earn-out liability with a value of $267,000 that is subject to the achievement of certain gross profit targets at Southern.  The earn-out period covers the period from June 2015 through December 2016, and the maximum earn-out that could be earned is $1,250,000. The common units issued with this acquisition were issued in a private offering conducted in accordance with the exemption from the registration requirements of Section 4(a)(2) of the Securities Act of 1933, as amended, as such units were issued to the owners of a business acquired in a privately negotiated transaction not involving any public offering or solicitation.

The fair value of the contingent earn-out liability was estimated by applying an expected present value technique based on the probability-weighted average of possible outcomes that would occur should certain financial metrics be reached. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs.

The following table represents our preliminary allocation of the total purchase price of this acquisition to the assets acquired (in thousands):

Goodwill associated with the Southern acquisition principally results from synergies expected from integrated operations. The Southern acquisition increased goodwill in our NGL distribution and sales segment to $37,141,000 as of September 30, 2015 from $31,335,000 as of December 31, 2014. The fair values of the acquired intangible assets were estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which ASC 820 refers to as Level 3 inputs. Trade names are amortized over an estimated useful life of one year, customer relationships are amortized over a weighted average useful life of 12 years, and non-compete agreements are amortized over a weighted average useful life of 5 years.

Revenues attributable to Southern included in the condensed consolidated statements of operations totaled $1,424,000 and $2,369,000 for the three months ended September 30, 2015 and the period from May 8, 2015 to September 30, 2015, respectively. We do not account for the operations of Southern on a stand-alone basis, therefore, it is impracticable to report the amounts of net income of Southern included in the condensed consolidated statements of operations related to the post-acquisition periods.

Disposition of crude oil supply and logistics assets. On September 30, 2015, we entered into an asset purchase agreement pursuant to which we intend to sell certain crude oil supply and logistics assets for a sales price of $1,750,000. We closed the transaction on November 2, 2015 and expect to recognize a gain on disposal of approximately $1,000,000.

6. Inventory

Inventory consists of the following as of September 30, 2015 and December 31, 2014:

7. Long-Term Debt

Long-term debt consists of the following at September 30, 2015 and December 31, 2014:

Bank of America Credit Agreement.  We have a $275,000,000 revolving credit facility with Bank of America, N.A. (the “BOA Credit Agreement”) that matures on February 12, 2019. As of September 30, 2015, the unused portion of our revolving credit facility was $79,170,000. Issued and outstanding letters of credit, which reduced available borrowings under the BOA Credit Agreement, totaled $28,830,000 at September 30, 2015.  Our revolving credit facility contains restrictions on our engaging in certain commodity transactions with respect to our crude oil logistics business. Pursuant to Amendment No. 4 dated as of November 6, 2015, we expanded the physical and financial swap transactions that are permitted in connection with our crude oil logistics business hedging program. Beginning in March 2015, we were inadvertently not in full compliance with previously existing restrictions under our revolving credit facility due to our engaging in certain financial swap contracts with a lender in our revolving credit facility. Such noncompliance was waived pursuant to Amendment No. 4. The financial swap contracts were executed as a part of our normal course hedging practices in compliance with our risk management policy and are now permitted under the terms of Amendment No. 4.

8. Derivative Instruments

We are exposed to certain market risks related to the volatility of commodity prices and changes in interest rates.  To monitor and manage these market risks, we have established comprehensive risk management policies and

procedures. We do not enter into derivative instruments for any purpose other than hedging commodity price risk and interest rate risk. We do not speculate using derivative instruments.

Commodity Price Risk. Our normal business activities expose us to risks associated with changes in the market price of crude oil and propane, among other commodities. Management believes it is prudent to limit our exposure to these risks, which include our (i) propane purchases, (ii) pre-existing or anticipated physical crude oil sales and (iii) certain crude oil held in inventory.  To meet this objective, we use a combination of fixed price swap and forward contracts. At times, we may also terminate or unwind hedges or portions of hedges in order to meet cash flow objectives or when the expected future volumes do not support the level of hedges. Our forward contracts that qualify for the Normal Purchase Normal Sale (“NPNS”) exception under GAAP are recognized when the underlying physical transaction is delivered.  While these contracts are considered derivative financial instruments under ASC 815, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings. 

In August 2015, we paid approximately $8,745,000 to settle all of our then-outstanding propane financial swap contracts that were scheduled to mature at various dates through April 2017. We simultaneously executed new propane financial swap contracts at then current forward market prices for the purpose of economically hedging a substantial majority of our fixed price propane sales contracts through July 2017.

The following table summarizes the net notional volume buy (sell) of our outstanding commodity-related derivatives, excluding those derivatives that qualified for the NPNS exception as of September 30, 2015 and December 31, 2014, none of which were designated as hedges for accounting purposes.

Interest Rate Risk. We are exposed to variable interest rate risk as a result of variable-rate borrowings under our revolving credit facilities. We entered into interest rate swap agreements to manage fluctuations in cash flows resulting from interest rate risk on a portion of our debt with a variable-rate component. These swaps change the variable-rate cash flow exposure on the debt obligations to fixed cash flows. Under the terms of the interest rate swaps, we receive variable interest rate payments and make fixed interest rate payments, thereby creating the equivalent of fixed-rate debt for the portion of the debt that is swapped.  As of December 31, 2014, our outstanding interest rate swap contracts contained a notional amount of $75,000,000.  Our interest rate swap agreements expired in July and September 2015.

Credit Risk. By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, we are exposed to counterparty credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk for us. When the fair value of a derivative contract is negative, we owe the counterparty and, therefore, we do not possess credit risk. We minimize the credit risk in derivative instruments by entering into transactions with high quality counterparties. We have entered into master netting agreements, including Master International Swap Dealers Association (“ISDA”) Agreements, which allow for netting of contract receivables and payables in the event of default by either party.

Fair Value of Derivative Instruments. We measure derivative instruments at fair value using the income approach, which discounts the future net cash settlements expected under the derivative contracts to a present value. These valuations primarily utilize level 2 inputs, including contractual terms, commodity prices, interest rates and yield curves observable at commonly quoted intervals. None of our derivative contracts are designated as hedging instruments. The following table summarizes the fair values of our derivative contracts included in the condensed consolidated balance sheets as of September 30, 2015 and December 31, 2014 on a gross basis without regard to same-counterparty netting.