Notes to Condensed Consolidated Financial Statements
(Unaudited)
1. Organization, Basis of Presentation and Summary of Significant Accounting Policies
General
American Midstream Partners, LP (the “Partnership”, “we”, “us”, or “our”) was formed on August 20, 2009 as a Delaware limited partnership for the purpose of owning, operating, developing and acquiring a diversified portfolio of midstream energy assets. The Partnership’s general partner, American Midstream GP, LLC (the “General Partner”), is
95%
owned by High Point Infrastructure Partners, LLC (“HPIP”) and
5%
owned by AIM Midstream Holdings, LLC. We hold our assets primarily in a number of limited liability companies,
two
limited partnerships and a corporation. Our capital accounts consist of notional General Partner units and limited partner interests.
Nature of Business
We are engaged in the business of gathering, treating, processing and transporting natural gas; gathering, transporting, storing, treating and fractionating NGLs; gathering, storing and transporting crude oil and condensates; and storing specialty chemical products, all through our ownership and operation of
13
gathering systems,
five
processing facilities,
three
fractionation facilities,
three
interstate pipelines,
five
intrastate pipelines,
three
marine terminal sites and
one
crude oil pipeline. Our primary assets, which are strategically located in Alabama, Georgia, Louisiana, Mississippi, North Dakota, Tennessee, Texas and the Gulf of Mexico, provide critical infrastructure that links producers of natural gas, crude oil, NGLs, condensate and specialty chemicals to numerous intermediate and end-use markets. We operate more than
3,000
miles of pipelines that gather and transport over
1.1
Bcf/d of natural gas and operate approximately
2.4 million
barrels of storage capacity across
three
marine terminal sites.
Basis of Presentation
These unaudited condensed consolidated financial statements have been prepared in accordance with GAAP for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for annual financial statements. The year-end balance sheet data was derived from consolidated audited financial statements but does not include disclosures required by GAAP for annual periods. The information furnished herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for a fair statement of financial position and results of operations for the respective interim periods.
Our financial results for the
three and nine months ended
September 30, 2016
, are not necessarily indicative of the results that may be expected for the year ending December 31,
2016
. These unaudited condensed consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended
December 31, 2015
, filed with the Securities and Exchange Commission (the “SEC”) on March 7, 2016 (“Annual Report”).
The accompanying unaudited condensed consolidated financial statements include the accounts of American Midstream Partners, LP, and its controlled subsidiaries. All significant inter-company accounts and transactions have been eliminated in consolidation.
Investment in Unconsolidated Affiliates
We hold various non-operated membership interests in entities that own and operate natural gas pipeline systems and NGL and crude oil pipelines in and around Louisiana, Alabama, Mississippi and the Gulf of Mexico. These non-operated membership interests in which the Partnership exercises significant influence, but does not control and of which is not the primary beneficiary, are accounted for using the equity method and are reported in
Investment in unconsolidated affiliates
in the accompanying unaudited condensed consolidated balance sheets.
The Partnership believes the equity method is an appropriate means to recognize increases or decreases, measured by GAAP, in the economic resources underlying the investments. Regular evaluation of these investments is appropriate to evaluate any potential need for impairment. The Partnership uses evidence of a loss in value to identify if an investment has incurred an other than temporary decline.
Restricted cash and cash equivalents
On September 30, 2016, Midla Financing, LLC (“Midla Financing”), American Midstream (Midla), LLC (“Midla”), and Mid Louisiana Gas Transmission LLC, (“MLGT” and, together with Midla, the “Note Guarantors”), each an indirect subsidiary of the Partnership entered into a Note Purchase and Guaranty Agreement (the “3.77% Senior Note Purchase Agreement”) with institutional investors in which Midla Financing sold
$60 million
in aggregate principal amount of senior secured notes due June 30, 2031 that bear interest at a rate of
3.77%
per annum (the “
3.77%
Senior Notes”). The
3.77%
Senior Notes were issued at par and provided net proceeds of approximately
$57.7 million
(after deducting related issuance costs). On September 30, 2016, we used
$14.0 million
of the proceeds to pay down a portion of our Credit Agreement (as defined herein).
The remainder of the net proceeds are contractually restricted and will be used to fund the retirement of Midla’s existing 1920’s vintage pipeline and the construction of a new replacement pipeline from Winnsboro, Louisiana to Natchez, Mississippi (the “Midla-Natchez Line”). The
3.77%
Senior Note Purchase Agreement allows the Partnership to reimburse itself for cash previously spent on the retirement of the former Midla pipeline and construction of the Midla-Natchez Line. As of September 30, 2016, we had restricted cash of
$43.7 million
. Please read
Note 12 -
Debt Obligations
-
3.77% Senior Notes
and
Note 16 - Commitments and Contingencies
for further discussion
.
We have included the net proceeds in
Other assets
on our unaudited condensed consolidated balance sheet. Construction on the Midla-Natchez Line commenced in the second quarter of 2016 and we expect service to begin in the first six months of 2017.
Allowance for doubtful accounts
We establish provisions for losses on accounts receivable when we determine that we will not collect all or part of an outstanding receivables balance. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of
September 30, 2016
, the Partnership recorded allowances for doubtful accounts of
$0.1 million
. As of
December 31, 2015
, the Partnership did
no
t record an allowance for doubtful accounts.
Use of Estimates
When preparing condensed consolidated financial statements in conformity with GAAP, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and assumptions are based on information available at the time such estimates and assumptions are made. Adjustments made with respect to the use of these estimates and assumptions often relate to information not previously available. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. Estimates and assumptions are used in, among other things, (i) estimating unbilled revenues, product purchases and operating and general and administrative costs, (ii) developing fair value assumptions, including estimates of future cash flows and discount rates, (iii) analyzing long-lived assets, goodwill and intangible assets for possible impairment, (iv) estimating the useful lives of assets and (v) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from our estimates.
New Accounting Pronouncements
Accounting Standards Issued and Adopted
In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-06,
Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments,
which clarifies existing guidance for assessing embedded call (put) options that are closely related to their debt hosts using a four-step decision sequence. ASU No. 2016-06 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption is permitted. The Partnership has adopted this guidance and determined it will not have a material impact on its consolidated financial statements and related disclosures.
In March 2016, the FASB issued ASU No. 2016-07,
Investments - Equity Method and Joint Ventures (Topic 323): Simplifying the
Transition to the Equity Method of Accounting,
which eliminates the requirement to retroactively adopt the equity method of accounting when a previous investment becomes qualified as a result of an increase in the level of ownership interest or degree of influence. ASU No. 2016-07 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal periods. Early adoption is permitted. The Partnership has adopted this guidance and determined it will not have a material impact on its consolidated financial statements and related disclosures.
Accounting Standards Issued Not Yet Adopted
In May 2014, the FASB issued ASU No. 2014-09,
Revenue from Contracts with Customers (Topic 606),
which amends the existing accounting standards for revenue recognition. The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2015-14 was subsequently issued and deferred the effective date to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that period. In March 2016, the FASB issued ASU No. 2016-08,
Revenue from Contracts with Customers (Topic 606): Principal Versus Agent Considerations
, as further clarification on principal versus agent considerations. Subsequently, in April 2016, the FASB issued ASU No. 2016-10,
Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing
as further clarification on identifying performance obligations and the licensing implementation guidance. In May 2016, the FASB issued ASU No. 2016-12,
Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients
,
as clarifying guidance on specific narrow scope improvements and practical expedients. The Partnership is currently evaluating the adoption of these standards and their impact on its consolidated financial statements and related disclosures.
In February 2016, the FASB issued ASU No. 2016-02,
Leases (Topic 842)
, which requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. ASU No. 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. The Partnership is currently evaluating the method of adoption and impact this standard will have on its consolidated financial statements and related disclosures.
In March 2016, the FASB issued ASU No. 2016-09,
Compensation - Stock Compensation (Topic 718): Improvements to Employee
Share-Based Payment Accounting.
This amendment involves the simplification of several aspects of accounting for share-based payment transactions, including income tax consequences, classification of awards as either equity or liability, and classification on the statement of cash flows. ASU No. 2016-09 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal periods. Early adoption is permitted. The Partnership is currently evaluating the method of adoption and impact this standard will have on its consolidated financial statements and related disclosures.
In June 2016, the FASB issued ASU No. 2016-13
, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,
which requires financial assets measured at amortized cost basis to be presented at the net amount expected to be collected. The new standard applies to trade receivables and requires expected credit losses to be based on past events, current conditions and reasonable and supportable forecasts that affect the instrument’s collectability. ASU No. 2016-13 is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal periods. Early adoption is permitted. The Partnership is currently evaluating the impact this standard will have on its consolidated financial statements and related disclosures.
In August 2016, the FASB issued ASU No. 2016-15
, Statement of Cash Flows (Topic 320): Classification of Cash Receipts and Cash Payments,
which addresses eight specific cash flow issues with the objective of reducing the existing diversity of presentation and classification in the statement of cash flows. The new standard applies to cash flows associated with debt payment or debt extinguishment costs, settlement of zero-coupon debt or other debt instruments with coupon rates that are insignificant in relation to effective interest rate of borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. ASU No. 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal periods. Early adoption is permitted, but only if all amendments are adopted in the same period. The Partnership is currently evaluating the impact this standard will have on its consolidated financial statements and related disclosures.
2.
Acquisitions
Emerald Transactions
On April 25, 2016 and April 27, 2016, American Midstream Emerald, LLC (“Emerald”), a wholly-owned subsidiary of the Partnership, entered into
two
purchase and sale agreements with Emerald Midstream, LLC, an affiliate of ArcLight Capital Partners, LLC (“ArcLight”), the majority owner of our General Partner, for the purchase of membership interests in certain midstream entities.
On April 25, 2016, Emerald entered into the first purchase and sale agreement for the purchase of membership interests in entities that own and operate natural gas pipeline systems and NGL pipelines in and around Louisiana, Alabama, Mississippi, and the Gulf
of Mexico (the “Pipeline Purchase Agreement”). Pursuant to the Pipeline Purchase Agreement, Emerald acquired (i)
49.7%
of the issued and outstanding membership interests of Destin Pipeline Company, L.L.C. (“Destin”), (ii)
16.7%
of the issued and outstanding membership interests of Tri-States NGL Pipeline, L.L.C. (“Tri-States”), and (iii)
25.3%
of the issued and outstanding membership interests of Wilprise Pipeline Company, L.L.C. (“Wilprise” and collectively with Destin and Tri-States, the “Companies”), in exchange for approximately
$183.6 million
(the “Pipeline Transaction”).
The Destin pipeline is a FERC-regulated,
255
-mile natural gas transportation system with total capacity of
1.2
Bcf/d. The system originates offshore in the Gulf of Mexico and includes connections with
four
producing platforms, and
six
producer-operated laterals, including the Partnership’s non-operated indirect interest in the Delta House floating production system and related pipeline infrastructure (“Delta House”). The
120
-mile offshore portion of the Destin system terminates at the Pascagoula processing plant, owned by Enterprise Products Partners, LP, and is the single source of raw natural gas to the plant. The onshore portion of Destin is the sole delivery point for merchant-quality gas from the Pascagoula processing plant and extends
135
miles north in Mississippi. Destin currently serves as the primary transfer of gas flows from the Barnett and Haynesville shale plays to Florida markets through interconnections with major interstate pipelines. Contracted volumes on the Destin pipeline are based on life-of-field dedication, dedicated volumes over a given period, or interruptible volumes as capacity permits. We became the operator of the Destin pipeline on November 1, 2016. The Tri-States pipeline is a FERC-regulated,
161
-mile NGL pipeline and sole form of transport to Louisiana-based fractionators for NGLs produced at the Pascagoula plant served by Destin and other facilities. The Wilprise pipeline is a FERC-regulated, approximately
30
-mile NGL pipeline that originates at the Kenner Junction and terminates in Sorrento, Louisiana, where volumes flow via pipeline to a Baton Rouge fractionator.
On April 27, 2016, Emerald entered into a second purchase and sale agreement for the purchase of
66.7%
of the issued and outstanding membership interests of Okeanos Gas Gathering Company, LLC (“Okeanos”), in exchange for a cash purchase price of approximately
$27.4 million
(such Purchase and Sale Agreement, the “Okeanos Purchase Agreement,” and such transaction, the “Okeanos Transaction,” and together with the Pipeline Transaction, the “Emerald Transactions”). The Okeanos pipeline is a
100
-mile natural gas gathering system located in the Gulf of Mexico with a total capacity of
1.0
Bcf/d. The Okeanos pipeline connects
two
platforms and
one
lateral, terminating at the Destin Main Pass 260 platform in the Mississippi Canyon region of the Gulf of Mexico. Contracted volumes on the Okeanos pipeline are based on life-of-field dedication.We became the operator of the Okeanos pipeline on November 1, 2016.
The Partnership funded the aggregate purchase price for the Emerald Transactions with the issuance of
8,571,429
Series C convertible preferred units (the “Series C Units”) representing limited partnership interests in the Partnership and a warrant (the “Warrant”) to purchase up to
800,000
common units representing limited partnership interests in the Partnership (“common units”) at an exercise price of
$7.25
per common unit amounting to a combined value of approximately
$120.0 million
, plus additional borrowings of
$91.0 million
under our Credit Agreement (as defined herein). Affiliates of our General Partner hold and participate in distributions on our Series C Units with such distributions being made in paid-in-kind Series C Units, cash or a combination thereof at the election of the Board of Directors of our General Partner.
Because our interests in the entities underlying the Emerald Transactions were previously owned by an affiliate of our General Partner, we accounted for our investments at our affiliate’s carry-over basis of
$212.0 million
, which is recorded in
Investment in unconsolidated affiliates
in our unaudited condensed consolidated balance sheets, and as an investing activity of
$100.9 million
within the unaudited condensed consolidated statements of cash flows. The amount by which the carry-over basis exceeded total consideration was
$1.0 million
and is recorded as a contribution from our General Partner within the unaudited condensed consolidated statements of changes in partners’ capital and noncontrolling interests.
For the
three and nine months ended
September 30, 2016
, the Partnership recorded
$2.5 million
and
$6.7 million
in earnings, respectively, and received cash distributions of
$12.5 million
and
$17.9 million
, respectively, from the entities underlying the Emerald Transactions. The excess of the cash distributions received over the earnings recorded is classified as proceeds from
Investment in unconsolidated affiliates, return of capital
within cash flows from investing activities in our unaudited condensed consolidated statements of cash flows.
Gulf of Mexico Pipeline
On April 15, 2016, American Panther, LLC (“American Panther”), a
60%
-owned subsidiary of the Partnership, acquired approximately
200
miles of crude oil, natural gas, and salt water onshore and offshore Gulf of Mexico pipelines (“Gulf of Mexico Pipeline”) for approximately
$2.7 million
in cash and the assumption of certain asset retirement obligations. The Partnership exerts control over American Panther and therefore consolidates its financial activity for financial reporting purposes.
The acquisition was accounted for using the acquisition method of accounting and as a result, the aggregate purchase price was allocated to the assets acquired and liabilities assumed based on their respective estimated fair values as of the acquisition date.
The fair value of these assets and liabilities are measured on a nonrecurring basis and are classified as Level 3 within the fair value hierarchy.
During the three months ended September 30, 2016, there was a reduction in the purchase price of
$0.4 million
which resulted in a corresponding decrease in the amount allocated to property, plant, and equipment. The following table summarizes the fair value of consideration transferred by the Partnership for the acquisition and the adjusted allocation of the purchase price to the assets acquired based on their respective fair values as of the acquisition date (in thousands):
|
|
|
|
|
|
|
|
Fair value of consideration transferred:
|
|
|
Cash
|
$
|
2,676
|
|
|
|
|
|
|
|
|
|
Fair value of assets acquired, liabilities assumed:
|
|
|
Assets:
|
|
|
Property, plant and equipment:
|
|
|
Pipelines
|
$
|
16,555
|
|
|
Land
|
421
|
|
|
Total property, plant and equipment
|
16,976
|
|
|
Liabilities:
|
|
|
Asset retirement obligations
|
(14,300
|
)
|
|
Fair value of net assets acquired and liabilities assumed
|
$
|
2,676
|
|
American Panther contributed revenues of
$4.6 million
and
$8.9 million
and net income of
$2.7 million
and
$5.3 million
for the
three and nine months ended
September 30, 2016
, respectively, which are included in the Partnership’s Gathering and Processing segment. During the
nine months ended
September 30, 2016
, the Partnership incurred
$0.2 million
of transaction costs related to the acquisition which are included in
Selling, general and administrative expenses
in our unaudited condensed consolidated statements of operations for the periods. We incurred immaterial transaction costs related to the acquisition during the three months ended
September 30, 2016
.
Pro forma financial results are not presented as it is impractical to obtain the necessary information. The seller did not operate the acquired assets as a standalone business and, therefore, historical financial information is not available.
Additional Delta House Investment
On April 25, 2016, American Midstream Delta House, LLC (“AMID Delta House”), a wholly-owned subsidiary of the Partnership, entered into a unit purchase agreement with an affiliate of ArcLight, pursuant to which AMID Delta House acquired
100%
of the outstanding membership interests in D-Day Offshore Holdings, LLC (“D-Day”), which owned (i)
912.4
Class A Units of Delta House FPS LLC (“FPS Equity”) and (ii)
53.5
Class A Units of Delta House Oil and Gas Lateral LLC (collectively, the “D-Day investment”) in exchange for a cash purchase price of approximately
$9.9 million
funded with additional borrowings under the Partnership’s Credit Agreement (as defined herein). Delta House is a floating production system platform with associated crude oil and natural gas export pipelines, located in the Mississippi Canyon region of the deepwater Gulf of Mexico.
Because our interest in D-Day was previously owned by an affiliate of our General Partner, we have accounted for our investment at our affiliate’s carry-over basis of
$9.9 million
, which is recorded in
Investments in unconsolidated affiliates
on our unaudited condensed consolidated balance sheets and as an investing activity within the unaudited condensed consolidated statements of cash flows. For the
three and nine months ended
September 30, 2016
, the Partnership recorded
$0.5 million
and
$0.9 million
in earnings from the D-Day investment, respectively. The Partnership received distributions from the D-Day investment of
$0.9 million
and
$2.0 million
for the
three and nine months ended
September 30, 2016
, respectively. The excess of the cash distributions received over the earnings recorded is classified as a return of capital within cash flows from investing activities in our unaudited condensed consolidated statements of cash flows.
The investment in D-Day, together with our
26.3%
interest in Pinto Offshore Holdings, LLC, an entity that owns a
49.0%
non-operated interest in Delta House, results in the Partnership holding non-operated direct and indirect interests in Delta House of
13.9%
, as of
September 30, 2016
. Please read
Note 19
-
Subsequent Events
for our acquisition of an additional non-operated direct interest in Delta House in October 2016. Pursuant to the agreements governing the underlying entities, we have no management
control or authority over the day-to-day operations of Delta House. Our interests in Delta House are accounted for as investments in unconsolidated affiliates in the unaudited condensed consolidated financial statements.
Divestitures
On September 14, 2015, the Partnership disposed of certain terminal assets in Salisbury, Maryland that were previously held for sale, with a book value approximating the sales proceeds of
$0.9 million
, resulting in a non-cash loss on disposal of less than
$0.1 million
. Of the proceeds received, the Partnership distributed
$0.4 million
to our General Partner.
On June 1, 2015, the Partnership disposed of certain non-strategic off-shore transmission assets in Louisiana with a net book value of
$3.0 million
for nominal proceeds, resulting in a non-cash loss on disposal of
$3.0 million
.
3. Concentration of Credit Risk and Trade Accounts Receivable
Our primary assets, which are strategically located in Alabama, Georgia, Louisiana, Mississippi, North Dakota, Tennessee, Texas and the Gulf of Mexico, provide critical infrastructure that links producers of crude oil, natural gas, NGLs, condensate and specialty chemicals (our customers) to numerous intermediate and end-use markets. As a result of recent acquisitions and geographic diversification, we have reduced the concentration of trade receivable balances due from these customer groups. Our customers’ historical financial and operating information is analyzed prior to extending credit. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures and for certain transactions, we may request letters of credit, prepayments or guarantees. We maintain allowances for potentially uncollectible accounts receivable. For both the
three and nine months ended
September 30, 2016
we recognized bad debt expense of
$0.1 million
and for the
three and nine months ended
2015
, no allowances were recorded.
During the
three and nine months ended
September 30, 2016
, one customer accounted for
13%
and
12%
, respectively, of the Partnership’s consolidated revenue. During the
three months ended September 30, 2015
, one customer accounted for
12%
of the Partnership’s consolidated revenue. During the
nine months ended September 30, 2015
,
no
individual customer accounted for 10% or more of the Partnership’s consolidated revenue.
4. Other Current Assets
Other current assets consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
December 31,
|
|
|
2016
|
|
2015
|
|
Prepaid insurance
|
$
|
1,370
|
|
|
$
|
3,948
|
|
|
Other receivables
|
1,793
|
|
|
1,573
|
|
|
Gas imbalance receivable
|
1,901
|
|
|
—
|
|
|
Other prepaid amounts
|
1,000
|
|
|
2,866
|
|
|
Other current assets
|
2,819
|
|
|
1,707
|
|
|
Total
|
$
|
8,883
|
|
|
$
|
10,094
|
|
5
. Derivatives
Commodity Derivatives
To limit the effect of commodity price changes and maintain our cash flow and the economics of our development plans, we enter into commodity derivative contracts from time to time. The terms of the contracts depend on various factors, including management’s view of future commodity prices, economics on purchased assets and future financial commitments. The hedging program is designed to mitigate the effect of commodity price declines while allowing us to participate in commodity price increases. Management regularly monitors the commodity markets and financial commitments to determine if, when and at what level commodity hedging is appropriate in accordance with policies that are established by the board of directors of our General Partner. Currently, our commodity derivatives are in the form of swaps. As of
September 30, 2016
, the aggregate notional volume of our commodity derivatives was
2.7 million
gallons of NGLs, natural gas and crude oil equivalent for
2016
production.
We enter into commodity derivative contracts with multiple counterparties, and in some cases, may be required to post collateral with our counterparties in connection with our derivative positions. As of
September 30, 2016
, we were not required to post collateral with any counterparty. The counterparties are not required to post collateral with us in connection with their derivative positions. Netting agreements are in place that permit us to offset our commodity derivative asset and liability positions with our counterparties.
We did not designate our commodity derivatives as hedges for accounting purposes. As a result, our commodity derivatives are accounted for at fair value in our condensed consolidated balance sheets with changes in fair value recognized currently in earnings.
Interest Rate Swaps
To manage the impact of the interest rate risk associated with our Credit Agreement (as defined herein), we enter into interest rate swaps from time to time, effectively converting a portion of the cash flows related to our long-term variable rate debt into fixed rate cash flows. As of
September 30, 2016
, the total notional amount of our interest rate swaps was
$300.0 million
.
In the first quarter of 2016, we entered into an interest rate swap with a notional amount of
$200.0 million
. The interest rate swap was entered into with a single counterparty and we were not required to post collateral. The interest rate swap is effective beginning January 3, 2017 and will expire September 3, 2019.
In the second quarter of 2016, we entered into additional interest rate swap with a notional amount of
$100.0 million
. The interest rate swap was entered into with a single counterparty and we were not required to post collateral. The interest rate swap is effective beginning January 1, 2018 and will expire December 31, 2021.
Weather Derivative
In the second quarter of 2016, we entered into a weather derivative to mitigate the impact of potential unfavorable weather on our operations under which we could receive payments totaling up to
$30.0 million
in the event that a hurricane or hurricanes of certain strength pass through the areas identified in the derivative agreement. The weather derivative is accounted for using the intrinsic value method. The weather derivative was entered into with a single counterparty and we were not required to post collateral.
We paid premiums of
$1.0 million
and
$0.9 million
during the
nine months ended September 30, 2016
and
2015
, respectively, which were recorded as current
Risk management assets
on our unaudited condensed consolidated balance sheets and are being amortized to
Direct operating expenses
on a straight-line basis over the term of the contract of
one year
. Unamortized amounts associated with the weather derivatives were approximately
$0.7 million
and
$0.4 million
as of
September 30, 2016
and
December 31, 2015
.
As of
September 30, 2016
and
December 31, 2015
, the value associated with our commodity derivatives, interest rate swaps and weather derivative were recorded on our unaudited condensed consolidated balance sheets as follows (in thousands):
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Risk Management Assets
|
|
Gross Risk Management Liabilities
|
|
Net Risk Management Assets (Liabilities)
|
|
Balance Sheet Classification
|
|
September 30,
2016
|
|
December 31, 2015
|
|
September 30,
2016
|
|
December 31, 2015
|
|
September 30,
2016
|
|
December 31, 2015
|
|
Current
|
|
$
|
687
|
|
|
$
|
365
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
687
|
|
|
$
|
365
|
|
|
Non current
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total assets
|
|
$
|
687
|
|
|
$
|
365
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
687
|
|
|
$
|
365
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(604
|
)
|
|
$
|
—
|
|
|
$
|
(604
|
)
|
|
$
|
—
|
|
|
Non current
|
|
—
|
|
|
—
|
|
|
(826
|
)
|
|
—
|
|
|
(826
|
)
|
|
—
|
|
|
Total liabilities
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1,430
|
)
|
|
$
|
—
|
|
|
$
|
(1,430
|
)
|
|
$
|
—
|
|
For the
three and nine months ended
September 30, 2016
and
2015
, respectively, the realized and unrealized gains (losses) associated with our commodity derivatives, interest rate swaps and weather derivative were recorded in our unaudited condensed consolidated statements of operations as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
|
|
Gain (Loss) on Derivatives
|
|
Gain (Loss) on Derivatives
|
|
Statement of Operations Classification
|
Realized
|
|
Unrealized
|
|
Realized
|
|
Unrealized
|
|
2016
|
|
|
|
|
|
|
|
|
Gain (loss) on commodity derivatives, net
|
$
|
(169
|
)
|
|
$
|
316
|
|
|
$
|
(413
|
)
|
|
$
|
(309
|
)
|
|
Interest expense
|
—
|
|
|
1,642
|
|
|
—
|
|
|
(1,121
|
)
|
|
Direct operating expenses
|
(258
|
)
|
|
—
|
|
|
(708
|
)
|
|
—
|
|
|
Total
|
$
|
(427
|
)
|
|
$
|
1,958
|
|
|
$
|
(1,121
|
)
|
|
$
|
(1,430
|
)
|
|
2015
|
|
|
|
|
|
|
|
|
Gain on commodity derivatives, net
|
$
|
575
|
|
|
$
|
241
|
|
|
$
|
966
|
|
|
$
|
308
|
|
|
Interest income (expense)
|
(36
|
)
|
|
69
|
|
|
(240
|
)
|
|
215
|
|
|
Direct operating expenses
|
(219
|
)
|
|
—
|
|
|
(694
|
)
|
|
—
|
|
|
Total
|
$
|
320
|
|
|
$
|
310
|
|
|
$
|
32
|
|
|
$
|
523
|
|
6. Fair Value Measurement
We apply the market approach for recurring fair value measurements, employing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We have consistently used the same valuation techniques for all periods presented. Please read
Note 1 - Organization, Basis of Presentation and Summary of Significant Accounting Policies - Fair Value Measurements
and
Note 7 - Fair Value Measurement
in our Annual Report for further discussion.
We believe the carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximates fair value because of the short-term maturity of these instruments.
The recorded value of the amount outstanding under the Credit Agreement (as defined herein) approximates its fair value, as interest rates are variable, based on prevailing market rates, and due to the short-term nature of borrowings and repayments under the Credit Agreement (as defined herein).
The recorded value of the
3.77%
Senior Notes approximates its fair value as the notes were issued on September 30, 2016. The fair value of our fixed interest
3.77%
Senior Notes will be classified as a Level 3 measurement as defined by ASC 820.
The fair value of our commodity and interest rate derivatives instruments are estimated using a market valuation methodology based upon forward commodity price curves, volatility curves as well as other relevant economic measures, if necessary. Discount factors may be utilized to extrapolate a forecast of future cash flows associated with long dated transactions or illiquid market points. The inputs are obtained from independent pricing services, and we have made no adjustments to the obtained prices.
We will recognize transfers between levels at the end of the reporting period in which the transfer occurred. There were
no
such transfers during the
nine months ended
September 30, 2016
and
2015
.
Fair Value of Financial Instruments
The following table sets forth, by level within the fair value hierarchy, our commodity derivative instruments and interest rate swaps, included as part of
Risk management assets
and
Risk management liabilities
within our unaudited condensed consolidated balance sheets, that were measured at fair value on a recurring basis as of
September 30, 2016
and
December 31, 2015
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carrying
Amount
|
|
Estimated Fair Value of the Assets (Liabilities)
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Commodity derivative instruments, net:
|
|
|
|
|
|
|
|
|
|
|
September 30, 2016
|
$
|
(309
|
)
|
|
$
|
—
|
|
|
$
|
(309
|
)
|
|
$
|
—
|
|
|
$
|
(309
|
)
|
|
December 31, 2015
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Interest rate swaps:
|
|
|
|
|
|
|
|
|
|
|
September 30, 2016
|
$
|
(1,121
|
)
|
|
$
|
—
|
|
|
$
|
(1,121
|
)
|
|
$
|
—
|
|
|
$
|
(1,121
|
)
|
|
December 31, 2015
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
The unamortized portion of the premium paid in relation to the weather derivative described in
Note
5
- Derivatives
is included within
Risk management assets
on our unaudited condensed consolidated balance sheets, however is not included as part of the above table as it is recorded at amortized carrying cost, not fair value.
Non Financial Assets and Liabilities
Non financial assets and liabilities that are measured at fair value on a nonrecurring basis are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of such assets and liabilities and their placement within the fair value hierarchy.
The fair values of asset retirement obligations are recurring and require significant Level 3 inputs. Please see a reconciliation of our asset retirement obligations and further discussion regarding the inputs in
Note 11 -
Asset Retirement Obligations
. The fair values of certain property acquisitions and business combinations are nonrecurring and require significant Level 3 inputs. Please see further discussion in
Note 2 -
Acquisitions
.
7. Property, Plant and Equipment, Net
Property, plant and equipment, net, as of
September 30, 2016
and December 31,
2015
were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Useful Life
(in years)
|
|
September 30,
2016
|
|
December 31,
2015
|
|
Land
|
N/A
|
|
$
|
5,282
|
|
|
$
|
5,282
|
|
|
Construction in progress
|
N/A
|
|
84,613
|
|
|
46,045
|
|
|
Buildings and improvements
|
4 to 40
|
|
10,623
|
|
|
9,864
|
|
|
Processing and treating plants
|
8 to 40
|
|
102,067
|
|
|
97,784
|
|
|
Pipelines and compressors
|
3 to 40
|
|
574,460
|
|
|
554,400
|
|
|
Storage
|
20 to 40
|
|
57,918
|
|
|
58,394
|
|
|
Equipment
|
5 to 20
|
|
38,591
|
|
|
22,207
|
|
|
Total property, plant and equipment
|
|
|
873,554
|
|
|
793,976
|
|
|
Accumulated depreciation
|
|
|
(173,576
|
)
|
|
(145,963
|
)
|
|
Property, plant and equipment, net
|
|
|
$
|
699,978
|
|
|
$
|
648,013
|
|
Of the gross property, plant and equipment balances at
September 30, 2016
and
December 31, 2015
,
$142.6 million
and
$111.9 million
, respectively, were related to AlaTenn, Midla and High Point Gathering Systems, our FERC regulated interstate and intrastate assets.
Capitalized interest was
$0.7 million
and
$0.9 million
for the
three months ended September 30, 2016
and
2015
, respectively, and $
1.7 million
and $
1.6 million
for the
nine months ended September 30, 2016
and
2015
, respectively.
Depreciation expense was
$9.5 million
and
$7.9 million
for the
three months ended September 30, 2016
and
2015
, respectively, and $
27.7 million
and $
23.3 million
for the
nine months ended September 30, 2016
and
2015
, respectively.
In February 2016, the Partnership reached a settlement of certain indemnification claims with Energy Spectrum Partners VI LP and Costar Midstream Energy, LLC, the sellers in the Partnership’s acquisition of
100%
of the membership interests of Costar Midstream, L.L.C. (“Costar” and such acquisition, the “Costar Acquisition”), whereby
1,034,483
of the common units held in escrow were returned to the Partnership and canceled, while the Partnership agreed to pay the Costar sellers an additional
$0.7 million
in cash. The net impact of this settlement was recorded as a reduction in
Property, plant and equipment, net
and
Limited partner interests.
8. Goodwill and Intangible Assets, Net
The carrying value of goodwill as of
September 30, 2016
and
December 31, 2015
, all of which related to our Terminals segment, was
$16.3 million
. The goodwill was contributed to the Partnership as part of the acquisition of Blackwater Midstream Holdings LLC (“Blackwater”) and other related subsidiaries from an affiliate of our General Partner (the “Blackwater Acquisition”).
Intangible assets, net, consists of customer relationships and dedicated acreage agreements identified as part of the Costar and Lavaca acquisitions. These intangible assets have definite lives and are subject to amortization on a straight-line basis over their economic lives, currently ranging from
10 years
to
30 years
. Intangible assets, net, consist of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
December 31,
|
|
|
2016
|
|
2015
|
|
Gross carrying amount:
|
|
|
|
|
Customer relationships
|
$
|
53,400
|
|
|
$
|
53,400
|
|
|
Dedicated acreage
|
53,350
|
|
|
53,350
|
|
|
|
106,750
|
|
|
106,750
|
|
|
Accumulated amortization:
|
|
|
|
|
Customer relationships
|
$
|
(5,054
|
)
|
|
$
|
(3,124
|
)
|
|
Dedicated acreage
|
(3,994
|
)
|
|
(2,661
|
)
|
|
|
$
|
(9,048
|
)
|
|
$
|
(5,785
|
)
|
|
Net carrying amount:
|
|
|
|
|
Customer relationships
|
$
|
48,346
|
|
|
$
|
50,276
|
|
|
Dedicated acreage
|
49,356
|
|
|
50,689
|
|
|
|
$
|
97,702
|
|
|
$
|
100,965
|
|
Amortization expense related to our intangible assets totaled
$1.1 million
and
$1.2 million
for the
three months ended September 30, 2016
and
2015
, respectively, and $
3.3 million
and $
4.3 million
for the
nine months ended September 30, 2016
and
2015
, respectively.
9. Investment in unconsolidated affiliates
The following table summarizes our percentage ownership interests in investments in unconsolidated affiliates:
|
|
|
|
|
|
|
Percentage Ownership
|
|
Destin
|
49.7%
|
|
Tri-States
|
16.7%
|
|
Delta House
|
13.9%
|
|
Wilprise
|
25.3%
|
|
Okeanos
|
66.7%
|
|
Main Pass Oil Gathering Company, LLC (“MPOG”)
|
66.7%
|
|
Mesquite
|
47.3%
|
The following table presents the activity in the Partnership’s equity investments for the
nine months ended September 30, 2016
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Destin
|
|
Tri-States
|
|
Delta House
|
|
Others (1)
|
|
Total
|
|
Balances at December 31, 2015
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
56,525
|
|
|
$
|
25,776
|
|
|
$
|
82,301
|
|
|
Investments
|
122,830
|
|
|
56,681
|
|
|
9,873
|
|
|
32,515
|
|
|
221,899
|
|
|
Earnings in unconsolidated affiliates
|
3,140
|
|
|
1,373
|
|
|
21,943
|
|
|
3,527
|
|
|
29,983
|
|
|
Contributions
|
—
|
|
|
—
|
|
|
—
|
|
|
13,099
|
|
|
13,099
|
|
|
Distributions
|
(11,350
|
)
|
|
(2,092
|
)
|
|
(42,113
|
)
|
|
(7,242
|
)
|
|
(62,797
|
)
|
|
Balances at September 30, 2016
|
$
|
114,620
|
|
|
$
|
55,962
|
|
|
$
|
46,228
|
|
|
$
|
67,675
|
|
|
$
|
284,485
|
|
_______________________
(1) Includes activity associated with our non-operated interests in Wilprise, Okeanos, MPOG and Mesquite.
The following tables present the summarized combined financial information for the Partnership’s equity investments (amounts represent
100%
of investee financial information):
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheets:
|
September 30, 2016
|
|
December 31, 2015
|
|
Current assets
|
$
|
143,362
|
|
|
$
|
2,086
|
|
|
Non-current assets
|
1,388,584
|
|
|
288,617
|
|
|
Current liabilities
|
187,712
|
|
|
366
|
|
|
Non-current liabilities
|
489,667
|
|
|
23,617
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
|
Statements of Operations:
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
Total revenue
|
$
|
94,448
|
|
|
$
|
9,201
|
|
|
$
|
246,445
|
|
|
$
|
13,610
|
|
|
Operating expense
|
10,443
|
|
|
1,274
|
|
|
17,984
|
|
|
3,011
|
|
|
Net income
|
66,410
|
|
|
5,975
|
|
|
187,187
|
|
|
6,216
|
|
The unconsolidated affiliates described above were each determined to be variable interest entities due to disproportionate economic interests and decision making rights. In each case, the Partnership lacks the power to direct the activities that most significantly impact each unconsolidated affiliate’s economic performance. As the Partnership does not hold a controlling interest in these affiliates, the Partnership accounts for its related investments using the equity method. The Partnership’s maximum exposure to loss related to each entity is limited to its equity investment as presented on the condensed consolidated balance sheet at
September 30, 2016
. In each case, the Partnership is not obligated to absorb losses greater than its proportional ownership percentages indicated above. In each case, the Partnership’s right to receive residual returns is not limited to any amount less than the proportional ownership percentages indicated above.
10. Accrued Expenses and Other Current Liabilities
Accrued expenses and other current liabilities were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
December 31,
|
|
|
|
2016
|
|
2015
|
|
Current portion of asset retirement obligation (1)
|
|
$
|
6,106
|
|
|
$
|
6,822
|
|
|
Accrued capital expenditures
|
|
8,151
|
|
|
3,984
|
|
|
Accrued expenses
|
|
10,638
|
|
|
3,178
|
|
|
Due to related parties
|
|
3,107
|
|
|
3,894
|
|
|
Accrued interest
|
|
5,228
|
|
|
1,411
|
|
|
Accrued property taxes
|
|
3,448
|
|
|
359
|
|
|
Accrued unitholder distribution (2)
|
|
5,000
|
|
|
—
|
|
|
Other
|
|
6,603
|
|
|
5,387
|
|
|
|
|
$
|
48,281
|
|
|
$
|
25,035
|
|
_______________________
(1) Associated with certain Gathering and Processing and Transmission assets.
(2) Please see
Note 17 - Related Party Transactions
for more information.
11.
Asset Retirement Obligations
We record a liability for the fair value of asset retirement obligations and conditional asset retirement obligations (collectively, referred to as “AROs”) that we can reasonably estimate, on a discounted basis, in the period in which the liability is incurred. Generally, the fair value of the liability is calculated using discounted cash flow techniques and based on internal estimates and assumptions related to (i) future retirement costs, (ii) future inflation rates and (iii) credit-adjusted risk-free interest rates. Significant increases or decreases in the assumptions would result in a significant change to the fair value measurement.
Certain assets related to our Transmission segment have regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned. These AROs include varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets
and returning the land to its original state. These assets have been in existence for many years and with regular maintenance will continue to be in service for many years to come. It is not possible to predict when demand for these transmission services will cease, however, we do not believe that such demand will cease for the foreseeable future. The majority of the current portion of our AROs is related to the retirement of the Midla pipeline discussed in
Note 16
-
Commitments and Contingencies
.
The following table is a reconciliation of our AROs for the
nine months ended September 30, 2016
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2015
|
$
|
35,371
|
|
|
Liabilities assumed (1)
|
14,300
|
|
|
Expenditures
|
(771
|
)
|
|
Accretion expense
|
1,082
|
|
|
Balances at September 30, 2016
|
$
|
49,982
|
|
|
Less: current portion
|
6,106
|
|
|
Long-term asset retirement obligation
|
$
|
43,876
|
|
_______________________
(1) As a result of the Gulf of Mexico Pipeline acquisition described in
Note 2
-
Acquisitions
, we recorded an ARO of
$14.3 million
.
We are required to establish security against any potential secondary obligations relating to the abandonment of certain transmission assets that may be imposed on the previous owner by applicable regulatory authorities. As such, we have a restricted cash account maintained by a third party that amounted to
$5.0 million
as of
September 30, 2016
and
December 31, 2015
and is presented in
Other assets, net
in our unaudited condensed consolidated balance sheets.
12.
Debt Obligations
Our outstanding borrowings were as follows at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
2016
|
|
December 31,
2015
|
|
Revolving credit facility
|
$
|
672,694
|
|
|
$
|
525,100
|
|
|
3.77% Senior Notes, due 2031
|
60,000
|
|
|
—
|
|
|
Other debt
|
—
|
|
|
2,338
|
|
|
Total debt obligations
|
732,694
|
|
|
527,438
|
|
|
Unamortized debt issuance costs (1)
|
(2,254
|
)
|
|
—
|
|
|
|
730,440
|
|
|
527,438
|
|
|
Less: Current portion, including unamortized debt issuance costs
|
1,351
|
|
|
2,338
|
|
|
Total debt obligation
|
$
|
729,089
|
|
|
$
|
525,100
|
|
_______________________
(1) Relates to the 3.77% Senior Notes at
September 30, 2016
.
Credit Agreement
Effective as of April 25, 2016, the Partnership entered into the Second Amendment to the Amended and Restated Credit Agreement (as amended, the “Credit Agreement”), which provided for maximum borrowings equal to
$750.0 million
, with the ability to further increase the borrowing capacity to
$900.0 million
, subject to lender approval. We can elect to have loans under our Credit Agreement bear interest either at a Eurodollar-based rate, plus a margin ranging from
2.00%
to
3.25%
depending on our total leverage ratio then in effect, or a base rate which is a fluctuating rate per annum equal to the highest of (i) the Federal Funds Rate, plus
0.50%
, (ii) the rate of interest in effect for such day as publicly announced from time to time by Bank of America as its “prime rate”, or (iii) the Eurodollar Rate plus
1.00%
, plus a margin ranging from
1.00%
to
2.25%
depending on the total leverage ratio then in effect. We also pay a commitment fee of
0.50%
per annum on the undrawn portion of the revolving loan under the Credit Agreement.
Our obligations under the Credit Agreement are secured by a lien on substantially all of our assets. Advances made under the Credit Agreement are guaranteed on a senior unsecured basis by certain of our subsidiaries (the “Guarantors”). These guarantees are full and unconditional and joint and several among the Guarantors. The terms of the Credit Agreement include covenants that
restrict our ability to make cash distributions and acquisitions in some circumstances. The remaining principal balance of loans and any accrued and unpaid interest will be due and payable in full on the maturity date, which is September 5, 2019.
On September 30, 2016, in connection with the
3.77%
Senior Note Purchase Agreement, the Partnership entered into the Limited Waiver and Third Amendment to the Credit Agreement, which among other things, (i) allows Midla Holdings (as defined below), for so long as the
3.77%
Senior Notes are outstanding, to be excluded from guaranteeing the obligations under the Credit Agreement and being subject to certain convents thereunder, (ii) releases the lien granted under the original credit agreement on D-Day’s equity interests in FPS Equity, and (iii) deems the FPS Equity excluded property under the Credit Agreement. All other terms under the Credit Agreement remain the same.
The Credit Agreement contains certain financial covenants, including a consolidated total leverage ratio which requires our indebtedness not to exceed
4.75
times adjusted consolidated EBITDA for the prior twelve month period, adjusted in accordance with the Credit Agreement (except for the current and subsequent two quarters after the consummation of a permitted acquisition, at which time the covenant may be increased to
5.25
times adjusted consolidated EBITDA) and a minimum interest coverage ratio that requires our adjusted consolidated EBITDA to exceed consolidated interest charges by not less than
2.50
times. The financial covenants in our Credit Agreement may limit the amount available to us for borrowing to less than
$750.0 million
. In addition to the financial covenants described above, the Credit Agreement also contains customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). As of
September 30, 2016
, our consolidated total leverage ratio was
4.43
and our interest coverage ratio was
7.18
, which was in compliance with the related requirements.
For the
nine months ended September 30,
2016
and
2015
, the weighted average interest rate on borrowings under our Credit Agreement was approximately
4.27%
and
3.50%
, respectively.
At
September 30, 2016
and
December 31, 2015
, letters of credit outstanding under the Credit Agreement were
$7.6 million
and
$1.8 million
, respectively.
As of
September 30, 2016
, we were in compliance with the covenants included in the Credit Agreement. Our ability to maintain compliance with the consolidated total leverage and interest coverage ratios included in the Credit Agreement may be subject to, among other things, the timing and success of initiatives we are pursuing, which may include expansion capital projects, acquisitions or drop down transactions, as well as the associated financing for such initiatives.
3.77% Senior Notes
On September 30, 2016, Midla Financing, Midla, and MLGT entered into the
3.77%
Senior Note Purchase Agreement. with certain institutional investors (the “Purchasers”). Pursuant to the
3.77%
Senior Note Purchase Agreement, Midla Financing issued an aggregate of
$60.0 million
principal amount of Senior Notes to the Purchasers, which bear interest at a rate of
3.77%
per annum that is paid quarterly. Principal on the
3.77%
Senior Notes is payable in installments on the last business day of each fiscal quarter end beginning June 30, 2017. The
3.77%
Senior Notes are payable in full on June 30, 2031. The average quarterly principal payment is approximately
$1.1 million
.The
3.77%
Senior Notes were issued at par and provided net proceeds of approximately
$57.7 million
(after deducting related issuance costs). On September 30, 2016, we used
$14.0 million
of the proceeds to pay down a portion of our Credit Agreement. The
3.77%
Senior Note Purchase Agreement allows the Partnership to reimburse itself for cash previously spent on the retirement of the former Midla pipeline and construction of the Midla-Natchez Line. As of September 30, 2016, we had restricted cash of
$43.7 million
from the issuance of the
3.77%
Senior Notes.
The Note Purchase Agreement includes customary representations and warranties, affirmative and negative covenants (including financial covenants), and events of default that are customary for a transaction of this type. Many of these provisions apply not only to Midla Financing and the Note Guarantors, but also to American Midstream Midla Financing Holdings, LLC (“Midla Holdings”), a wholly owned subsidiary of the Partnership and the sole member of Midla Financing. Among other things, Midla Financing must maintain a debt service reserve account containing six months of principal and interest payments, and Midla Financing and the Note Guarantors (including any entities that become guarantors under the terms of the
3.77%
Senior Note Purchase Agreement) are restricted from making distributions (a) until June 30, 2017, (b) unless the debt service coverage ratio is not less than, and is not projected for the following 12 calendar months to be less than,
1.20
:1.00, and (c) unless certain other requirements are met.
In connection with the
3.77%
Senior Note Purchase Agreement, the Note Guarantors guaranteed the payment in full of all Midla Financing’s obligations under the
3.77%
Senior Note Purchase Agreement. Also, Midla Financing and the Note Guarantors granted a security interest in substantially all of their tangible and intangible personal property, including the membership interests in each Note Guarantor held by Midla Financing, and Midla Holdings pledged the membership interests in Midla Financing to the Collateral Agent. Please read
Note 16 -
Commitments and Contingencies
-
Guarantees
for further discussion.
Net proceeds from the
3.77%
Senior Notes are restricted and will be used (1) to fund project costs incurred in connection with (a) the construction of the Midla-Natchez Line, (b) the retirement of Midla’s existing 1920’s vintage pipeline, (c) the move of our Baton Rouge operations to the MLGT system, and (d) the reconfiguration of the DeSiard compression system and all related ancillary facilities, (2) to pay transaction fees and expenses in connection with the issuance of the
3.77%
Senior Notes, and (3) for other general corporate purposes of Midla Financing. Please read
Note 16 -
Commitments and Contingencies
-
Regulatory matters
for further discussion of the Midla-Natchez Line.
Other debt
Other debt represents insurance premium financing in the original amount of
$3.0 million
bearing interest at
3.95%
per annum, which was repaid in equal monthly installments of approximately
$0.3 million
through the third quarter of 2016.
13. Partners’ Capital and Convertible Preferred Units
Our capital accounts are comprised of approximately
1.3%
notional General Partner interests and
98.7%
limited partner interests as of
September 30, 2016
. Our limited partners have limited rights of ownership as provided for under our Partnership Agreement and the right to participate in our distributions. Our General Partner manages our operations and participates in our distributions, including certain incentive distributions pursuant to the incentive distribution rights that are non-voting limited partner interests held by our General Partner. Pursuant to our Partnership Agreement, our General Partner participates in losses and distributions based on its interest. The General Partner’s participation in the allocation of losses and distributions is not limited and therefore, such participation can result in a deficit to its capital account. As such, allocation of losses and distributions, including distributions for previous transactions between entities under common control, has resulted in a deficit to the General Partner’s capital account included in our condensed consolidated balance sheets.
Affiliates of our General Partner hold and participate in distributions on our Series A Units and Series C Units (see below for further details) with such distributions being made in paid-in-kind units, cash or a combination thereof, at the election of the Board of Directors of our General Partner. The Series A Units and Series C Units are entitled to vote along with Limited Partner common unitholders and such units are currently convertible to common units.
On February 1, 2016, all outstanding Series B Units were converted on a one-for-one basis into common units.
Prior to their conversion, our General Partner held and participated in distributions on our Series B Units with such distributions being made in cash or with paid-in-kind Series B Units. The holders of Series B Units were entitled to vote along with the holders of common units prior to conversion.
At-The-Market (“ATM”) Offering
On October 18, 2015, we filed a prospectus supplement related to the offer and sale from time to time of common units in an at-the-market offering. During the second quarter of 2016, we sold
248,561
common units for proceeds of
$3.0 million
, net of commissions and accrued offering costs of
$0.2 million
, which were used for general partnership purposes including the repayment of amounts outstanding under the Credit Agreement, the funding of acquisitions and the funding of capital expenditures. We sold
no
units during the third quarter of 2016. As of
September 30, 2016
, approximately
$96.8 million
remained available for sale under the Partnership’s ATM Equity Offering Sales Agreement.
Series C Convertible Preferred Units
On April 25, 2016, the Series C Units were created and issued pursuant to the Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP (“Partnership Agreement”).
The Series C Units have the right to receive cumulative distributions in the same priority as the Series A Units, which is before any other distributions made in respect of any other partnership interests, in the amounts described herein with such distributions being made in paid-in-kind units, cash or a combination thereof, at the election of the Board of Directors of our General Partner. If all or any portion of a distribution on the Series C Units is to be paid in cash, then the aggregate amount of such cash to be distributed in respect of the Series C Units outstanding will be paid out of available cash in the same priority as any cash distributions made to the Series A unitholders, which will be made prior to any distributions to the General Partner or our common unitholders. To the extent that any portion of a distribution on Series C units (or Series A units) to be paid in cash exceeds the amount of Available Cash (as defined in the Partnership Agreement), an amount of cash equal to the Available Cash will be paid pro rata to the Series A unitholders and the Series C unitholders and the balance of such Series A quarterly distribution and Series C quarterly distributions will become an arrearage until paid in a future quarter.
The Series C Units have voting rights that are identical to the voting rights of the common units and will vote with the common units as a single class on an as converted basis, with each Series C Unit initially entitled to
one
vote for each common unit into which such Series C Unit is convertible. The Series C Units also have separate class voting rights on any matter, including a merger, consolidation or business combination, that adversely affects, amends or modifies any of the rights, preferences, privileges or terms of the Series C Units. The Series C Units are convertible in whole or in part into common units at any time. The number of common units into which a Series C Unit is convertible will be an amount equal to (i) the sum of
$14.00
and all accrued and accumulated but unpaid distributions, divided by (ii) the conversion price.
In the event that the Partnership issues, sells or grants any common units or convertible securities at an indicative per common unit price that is less than
$14.00
per common unit (subject to customary anti-dilution adjustments), then the conversion price will be adjusted according to a formula to provide for an increase in the number of common units into which Series C Units are convertible.
Upon any liquidation and winding up of the Partnership or the sale of substantially all of the assets of the Partnership, the holders of Series C Units generally will be entitled to receive, in preference to the holders of any of the Partnership’s other securities, an amount equal to the sum of the
$14.00
multiplied by the number of Series C Units owned by such holders, plus all accrued but unpaid distributions.
Call Right
At any time prior to April 25, 2017, the Partnership has the right (the “Series C Call Right”) to require the holders of the Series C Units to sell, assign and transfer all or a portion of the then outstanding Series C Units to the Partnership for a purchase price of
$14.00
per Series C Unit (subject to customary anti-dilution adjustments), plus all accrued but unpaid distributions on each Series C Unit.
The Partnership may not exercise the Series C Call Right with respect to any Series C Unit if the holder has elected to convert it into common units on or prior to the date the Partnership has provided notice of its intent to exercise its Series C Call Right, and may not exercise the Series C Call Right if doing so would violate applicable law or result in a default under any financing agreement or obligation of the Partnership or its affiliates.
Warrant
On April 25, 2016, pursuant to the Securities Purchase Agreement, the Partnership issued the Warrant to Magnolia Infrastructure Partners, LLC (“Magnolia,” an affiliate of our General Partner), which allows it to purchase up to
800,000
common units at an exercise price of
$7.25
per common unit. The Warrant is subject to standard anti-dilution adjustments and is exercisable for a period of
seven
years.
On April 25, 2017, the number of common units that may be purchased pursuant to the exercise of the Warrant will be adjusted by an amount, rounded to the nearest whole common unit, equal to the product obtained by the following calculation: (i)
400,000
multiplied by (ii) (A) the Series C Issue Price multiplied by the number of Series C Units then outstanding less
$45.0 million
divided by (B) the Series C Issue Price multiplied by the number of Series C Units issued, less
$45.0 million
.
Any Series C Units issued in-kind as a distribution to holders of Series C Units (“Series C PIK Units”) will increase the number of common units that can be purchased upon exercise of the Warrant by an amount, rounded to the nearest whole common unit, equal to the product obtained by the following calculation: (i) the total number of common units into which each Warrant may be exercised immediately prior to the most recent issuance of the Series C PIK Units multiplied by (ii) (A) the total number of outstanding Series C Units immediately after the most recent issuance of Series C PIK Units divided by (B) the total number of outstanding Series C Units immediately prior to the most recent issuance of Series C PIK Units.
The fair value of the Warrant was determined using a market approach that utilized significant inputs which are not observable in the market and thus represent a Level 3 measurement as defined by ASC 820. The estimated fair value of
$4.41
per warrant unit was determined using a Black-Scholes model and the following significant assumptions: i) a dividend yield of
18%
, ii) common unit volatility of
42%
and iii) the
seven
-year term of the warrant to arrive at an aggregate fair value of
$4.5 million
.
General Partner Units
In order to maintain its ownership percentage, we received proceeds of
$1.9 million
from our General Partner as consideration for the issuance of
135,813
additional notional General Partner units for the
nine months ended
September 30, 2016
. For the
nine months ended
September 30, 2015
, we received proceeds of
$2.0 million
for the issuance of
143,517
additional notional General Partner units.
Outstanding Units
The number of units outstanding as of
September 30, 2016
and
December 31, 2015
, respectively, were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
September 30,
2016
|
|
December 31,
2015
|
|
Series A convertible preferred units
|
9,951
|
|
|
9,210
|
|
|
Series B convertible units
|
—
|
|
|
1,350
|
|
|
Series C convertible preferred units
|
8,664
|
|
|
—
|
|
|
Limited Partner common units
|
31,195
|
|
|
30,427
|
|
|
General Partner units
|
672
|
|
|
536
|
|
Distributions
We made cash distributions as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
Series A convertible preferred units
|
$
|
2,449
|
|
|
$
|
—
|
|
|
$
|
2,449
|
|
|
$
|
—
|
|
|
Series C convertible preferred units
|
1,302
|
|
|
—
|
|
|
1,302
|
|
|
—
|
|
|
Limited Partner common units
|
12,851
|
|
|
10,755
|
|
|
40,614
|
|
|
32,221
|
|
|
General Partner units
|
174
|
|
|
522
|
|
|
569
|
|
|
840
|
|
|
General Partners’ incentive distribution rights
|
—
|
|
|
1,293
|
|
|
1,806
|
|
|
3,874
|
|
|
Total
|
$
|
16,776
|
|
|
$
|
12,570
|
|
|
$
|
46,740
|
|
|
$
|
36,935
|
|
On October 20, 2016, we announced that the Board of Directors of our General Partner declared a quarterly cash distribution of
$0.4125
per common unit for the quarter ended
September 30, 2016
, or
$1.65
per common unit on an annualized basis. The distribution is expected to be paid on
November 14, 2016
, to unitholders of record as of the close of business on
November 3, 2016
.
At
September 30, 2016
, we accrued
$2.5 million
of contractual cash distributions and
$2.3 million
of paid-in-kind Series A Units that will be issued in November 2016. At
September 30, 2016
, we accrued
$1.8 million
of contractual cash distributions and
$1.8 million
of Series C PIK Units that will be issued in November 2016.
For the
nine months ended September 30, 2016
, the Partnership issued
740,735
of paid-in-kind Series A Units and accrued a combination of cash and paid-in-kind unitholder distributions for Series A Units with a fair value of
$11.4 million
. For the
nine months ended September 30, 2015
, the Partnership issued
613,706
of paid-in-kind Series A Units and accrued a combination of cash and paid-in-kind unitholder distributions for Series A Units with a fair value of
$12.6 million
.
For the
nine months ended September 30, 2016
, the Partnership issued
93,039
of Series C PIK Units and accrued a combination of cash and paid-in-kind unitholder distributions for Series C Units with a fair value of
$4.6 million
.
The fair value of the paid-in-kind Series A Unit and Series C Unit distributions for all quarters presented was determined primarily using the market and income approaches, requiring significant inputs which are not observable in the market and thus represent a Level 3 measurement as defined by ASC 820. Under the income approach, the fair value estimates for all periods presented were based on i) present value of estimated future contracted distributions, ii) option values ranging from
$0.02
per unit to
$1.88
per unit using a Black-Scholes model, and iii) assumed discount rate of
10.0%
.
Net Income (Loss) attributable to Limited Partners
Net income (loss) is allocated to the General Partner and the limited partners in accordance with their respective ownership percentages, after giving effect to distributions on Series A Units and Series C Units, and declared distributions on the Series B Units and General Partner units, including incentive distribution rights. Unvested unit-based payment awards that contain non-forfeitable rights to distributions (whether paid or unpaid) are classified as participating securities and are included in our computation of basic and diluted limited partners’ net income (loss) per common unit. Basic and diluted limited partners’ net income (loss) per common unit is calculated by dividing limited partners’ interest in net income (loss) by the weighted average number of outstanding limited partner units during the period.
We determined basic and diluted limited partners’ net income (loss) per common unit as follows (in thousands, except per unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
Net income (loss) from continuing operations
|
$
|
2,679
|
|
|
$
|
(4,574
|
)
|
|
$
|
(4,876
|
)
|
|
$
|
(5,740
|
)
|
|
Less: Net income attributable to noncontrolling interests
|
1,196
|
|
|
34
|
|
|
2,175
|
|
|
80
|
|
|
Net income (loss) from continuing operations attributable to the Partnership
|
1,483
|
|
|
(4,608
|
)
|
|
(7,051
|
)
|
|
(5,820
|
)
|
|
Less:
|
|
|
|
|
|
|
|
|
Distributions on Series A Units
|
4,806
|
|
|
4,991
|
|
|
13,878
|
|
|
12,598
|
|
|
Distributions on Series C Units
|
3,611
|
|
|
—
|
|
|
5,861
|
|
|
—
|
|
|
Declared distributions on Series B Units
|
—
|
|
|
324
|
|
|
—
|
|
|
1,157
|
|
|
General partner’s distribution
|
174
|
|
|
1,815
|
|
|
2,375
|
|
|
4,714
|
|
|
General partner’s share in undistributed loss
|
(265
|
)
|
|
(294
|
)
|
|
(928
|
)
|
|
(737
|
)
|
|
Net loss from continuing operations available to Limited Partners
|
(6,843
|
)
|
|
(11,444
|
)
|
|
(28,237
|
)
|
|
(23,552
|
)
|
|
Net loss from discontinued operations available to Limited Partners
|
—
|
|
|
(53
|
)
|
|
—
|
|
|
(79
|
)
|
|
Net loss available to Limited Partners
|
$
|
(6,843
|
)
|
|
$
|
(11,497
|
)
|
|
$
|
(28,237
|
)
|
|
$
|
(23,631
|
)
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common units used in computation of Limited Partners’ net loss per common unit - basic and diluted
|
31,168
|
|
|
23,987
|
|
|
30,979
|
|
|
23,154
|
|
|
|
|
|
|
|
|
|
|
|
Limited Partners’ net loss per common unit - basic and diluted (1)
|
$
|
(0.22
|
)
|
|
$
|
(0.48
|
)
|
|
$
|
(0.91
|
)
|
|
$
|
(1.02
|
)
|
_______________________
(1) Potential common unit equivalents are antidilutive for all periods and, as a result, have been excluded from the determination of diluted limited partners’ net income (loss) per common unit
14. Long-Term Incentive Plan
Our General Partner manages our operations and activities and employs the personnel who provide support to our operations. On November 19, 2015, the Board of Directors of our General Partner approved the Third Amended and Restated Long-Term Incentive Plan to increase the number of common units authorized for issuance by
6,000,000
common units. On February 11, 2016, the unitholders approved the Third Amended and Restated Long-Term Incentive Plan (as amended and as currently in effect as of the date hereof, the “LTIP”) which, among other things, increased the number of available awards by
6,000,000
common units. At
September 30, 2016
and
December 31, 2015
, there were
4,951,795
and
15,484
common units, respectively, available for future issuance under the LTIP.
All such equity-based awards issued under the LTIP consist of phantom units, Distribution Equivalent Rights (“DERs”) or Option Grants. DERs and options have been granted on a limited basis. Future awards, such as options and DERs, may be granted at the discretion of the Compensation Committee and subject to approval by the Board of Directors of our General Partner.
Phantom Unit Awards.
Ownership in the phantom unit awards is subject to forfeiture until the vesting date. The LTIP is administered by the Compensation Committee of the Board of Directors of our General Partner, which at its discretion, may elect to settle such vested phantom units with a number of common units equivalent to the fair market value at the date of vesting in lieu of cash. Although our General Partner has the option to settle in cash upon the vesting of phantom units, our General Partner has not historically settled these awards in cash. Under the LTIP, grants issued typically vest in increments of
25%
on each grant anniversary date and do not contain any vesting requirements other than continued employment.
In December 2015, the Board of Directors of our General Partner approved a grant of
200,000
phantom units under the LTIP which contain DERs based on the extent to which the Partnership’s Series A Unitholders receive distributions in cash and will vest in one lump sum installment on the three year anniversary of the date of grant, subject to acceleration in certain circumstances.
The following table summarizes activity in our phantom unit-based awards for the
nine months ended September 30, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Units
|
|
Weighted-Average Grant Price
|
|
Outstanding at beginning of period
|
|
569,759
|
|
|
$
|
13.15
|
|
|
Granted
|
|
1,342,016
|
|
|
1.89
|
|
|
Forfeited
|
|
(313,884
|
)
|
|
2.22
|
|
|
Vested
|
|
(243,828
|
)
|
|
12.97
|
|
|
Outstanding at end of period
|
|
1,354,063
|
|
|
$
|
4.55
|
|
The fair value of our phantom units, which are subject to equity classification, is based on the fair value of our common units at the grant date. For the
three months ended September 30, 2016
and
2015
, compensation costs related to these awards were
$1.4 million
and
$0.6 million
, respectively, and for the
nine months ended
September 30, 2016
and
2015
, were
$2.9 million
and $
2.8 million
, respectively. For the
three and nine months ended
September 30, 2016
,
$0.7 million
and $
2.2 million
, respectively, were classified as
equity compensation expense
. For both the
three and nine months ended
September 30, 2016
, the remaining
$0.7 million
related to the acceleration of equity awards for certain employees was classified as transaction costs within
Selling, general, and administrative expense
in our unaudited condensed consolidated statements of operations. Please see the
Note 16 -
Commitments and Contingencies
for further discussion. The entire balance for the
three and nine months ended
September 30, 2015
was classified as
Equity compensation expense
.
The total fair value of vested units at the time of vesting was
$1.8 million
and
$2.5 million
for the
nine months ended September 30, 2016
and
2015
, respectively.
Equity compensation expense related to unvested awards not yet recognized at
September 30, 2016
and
2015
was
$4.9 million
and
$5.5 million
, respectively, and the weighted average period over which this cost is expected to be recognized as of
September 30, 2016
was approximately
2.4 years
.
Performance and Service Condition Awards.
In November 2015, the Board of Directors of our General Partner modified awards to introduce certain performance and service conditions that we believe are probable of being achieved, amounting to
$2.0 million
payable in a variable amount of unit awards at the time of grant. Prior to the third quarter of 2016, these awards were accounted for as liability classified awards and equity-based compensation was accrued from the service-inception date through the estimated date of meeting both the performance and service conditions. During the third quarter of 2016, we decided to settle the obligation in cash. We reclassified previously recognized equity based compensation expense of
$0.6 million
from
equity compensation expense
to
direct operating expenses
in our condensed consolidated statement of operations. Expense related to these awards for the three and
nine months ended September 30, 2016
was
$0.6 million
and
$1.2 million
, respectively. Compensation costs related to unvested awards not yet recognized at
September 30, 2016
was
$0.3 million
.
Option to Purchase Common Units.
In December 2015, the Board of Directors of our General Partner approved the grant of an option to purchase
200,000
common units of the Partnership at an exercise price per unit equal to
$7.50
(the “December Option Grant”). The December Option Grant will vest in one lump sum installment on January 1, 2019, subject to acceleration in certain circumstances, and will expire on March 15th of the calendar year following the calendar year in which it vests.
In August 2016, the Board of Directors of our General Partner approved the grant of an option to purchase
30,000
common units of the Partnership at an exercise price per unit equal to
$12.00
(the “August Option Grant”).
The August Option Grant will vest in one lump sum installment on July 31, 2019, subject to continued employment with the Company, and will expire on July 31st of the calendar year following the calendar year in which it vests.
In September 2016, the Board of Directors of our General Partner approved the grant of an option to purchase
45,000
common units of the Partnership at an exercise price per unit equal to
$13.88
.
On the
one
year grant anniversary date
25%
of the option grant will vest, and the remaining
75%
will vest in
25%
increments on each succeeding anniversary date
. The option grants will expire September 30th of the calendar year following the calendar year in which it vests.
The following table summarizes our Option Grant awards, in units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, 2016
|
|
|
|
Units
|
|
Weighted-Average Exercise Price
|
|
Outstanding at beginning of period
|
|
200,000
|
|
|
$
|
7.50
|
|
|
Granted
|
|
75,000
|
|
|
13.13
|
|
|
Forfeited
|
|
—
|
|
|
—
|
|
|
Vested
|
|
—
|
|
|
—
|
|
|
Outstanding at end of period
|
|
275,000
|
|
|
$
|
9.03
|
|
Compensation costs related to these awards for the three and
nine months ended September 30, 2016
were immaterial. Compensation costs related to unvested awards not yet recognized at
September 30, 2016
was
$0.2 million
.
15. Income Taxes
With the exception of certain subsidiaries in our Terminals Segment, the Partnership is not subject to U.S. federal or state income taxes as such income taxes are generally borne by our unitholders through the allocation of our taxable income (loss) to them. The State of Texas does impose a franchise tax that is assessed on the portion of our taxable margin that is apportioned to Texas.
Income tax expense for the
three and nine months ended
September 30, 2016
was
$0.4 million
and $
1.3 million
, respectively, resulting in an effective tax rate of
14.1%
and
36.4%
, respectively. For the
three and nine months ended
September 30, 2015
, income tax expense was
$0.6 million
and $
1.1 million
, respectively, resulting in an effective tax rate of
14.9%
and
22.8%
, respectively.
The effective tax rates for the
three and nine months ended
September 30, 2016
and
2015
, differ from the statutory rate primarily due to the portion of the Partnership’s income and loss that is not subject to U. S. federal and state income taxes, as well as transactions between the Partnership and its taxable subsidiary that generate tax deductions for the taxable subsidiary, which are eliminated in consolidation.
16.
Commitments and Contingencies
Legal proceedings
We are not currently party to any pending litigation or governmental proceedings, other than ordinary routine litigation incidental to our business. While the ultimate impact of any proceedings cannot be predicted with certainty, our management believes that the resolution of any of our pending proceedings will not have a material adverse effect on our financial condition or results of operations.
Environmental matters
We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to natural gas pipelines, NGL and crude pipelines and their operation, as well as terminal operations and we could, at times, be subject to environmental cleanup and enforcement actions. We attempt to manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment.
Regulatory matters
On October 8, 2014, Midla reached an agreement in principle with its customers regarding the interstate pipeline that traverses Louisiana and Mississippi in order to provide continued service to its customers while addressing safety concerns with the existing pipeline.
On April 16, 2015, FERC approved the stipulation and agreement (the “Midla Agreement”) allowing Midla to retire the existing 1920’s vintage pipeline and replace it with the Midla-Natchez Line to serve existing residential, commercial, and industrial customers. Under the Midla Agreement, customers not served by the new Midla-Natchez Line will be connected to other interstate or intrastate pipelines, other gas distribution systems, or offered conversion to propane service. On June 29, 2015, the Partnership filed with FERC for authorization to construct the Midla-Natchez pipeline, which was approved on December 17, 2015. Construction commenced in the second quarter of 2016 with service expected to begin in the first six months of 2017. Under the Midla Agreement, Midla plans to execute long-term agreements seeking to recover its investment in the Midla-Natchez Line.
Exit and disposal costs
On March 9, 2016, management committed to a corporate relocation plan and communicated that plan to the impacted employees. The plan includes relocation assistance or one-time termination benefits for employees who render service until their respective termination date. Charges associated with one-time termination benefits were recognized ratably over the requisite service period and presented in
Selling, general and administrative expenses
in our
unaudited condensed consolidated statement of operations. For the
three and nine months ended
September 30, 2016
, we recorded
$5.3 million
and
$6.6 million
, respectively, in termination benefits. At
September 30, 2016
, our outstanding accrual was approximately
$0.8 million
and is recorded in
Accrued expenses and other current liabilities
in our unaudited condensed consolidated balance sheet. We expect the plan to be complete in the fourth quarter of 2016.
On August 31, 2016, we vacated our former corporate office space and recorded a
$0.4 million
liability for the present value of the remaining lease payments. We also entered into a new corporate office lease which commenced on August 1, 2016 and expires on August 15, 2032. Below is our contractual obligation related to the new corporate office lease (in thousands):
|
|
|
|
|
|
|
|
|
Office Lease
|
|
2016
|
$
|
—
|
|
|
2017
|
369
|
|
|
2018
|
895
|
|
|
2019
|
920
|
|
|
2020
|
945
|
|
|
Thereafter
|
12,844
|
|
|
|
$
|
15,973
|
|
17. Related Party Transactions
In December 2013, the Partnership completed a merger with Blackwater Midstream Holdings, LLC (“Blackwater”) and AL Blackwater, LLC (“ALB”), both affiliates of ArcLight, under which Blackwater became a wholly owned subsidiary of the Partnership. The merger was accounted for as a common control transaction.The merger agreement included a provision whereby ALB would be entitled to additional
$5.0 million
of merger consideration based on Blackwater’s assets meeting certain operating targets. During the third quarter of 2016, the Partnership determined that it was probable the operating targets would be met in early 2017 and recorded a
$5.0 million
accrued unitholder distribution in the accompanying condensed consolidated financial statements as of
September 30, 2016
.
Employees of our General Partner are assigned to work for the Partnership or other affiliates of our General Partner. Where directly attributable, all compensation and related expenses for these employees are charged directly by our General Partner to American Midstream, LLC, which, in turn, charges the appropriate subsidiary or affiliate. Our General Partner does not record any profit or margin on the expenses charged to us. During the
three and nine months ended
September 30, 2016
, expenses of
$11.6 million
and $
28.5 million
, respectively, were charged to the Partnership by our General Partner. During the
three and nine months ended
September 30, 2015
, expenses of $
7.2 million
and $
21.4 million
, respectively, were charged to the Partnership by our General Partner.
During the second quarter of 2014, the Partnership and an affiliate of its General Partner entered into a Management Service Fee arrangement under which the affiliate pays a monthly fee to reimburse the Partnership for administrative expenses incurred on the affiliate’s behalf. For the
three and nine months ended
September 30, 2016
, the Partnership recognized
$0.2 million
and $
0.6 million
, respectively, in management fee income, and recognized $
0.3 million
and
$1.2 million
, respectively, for the
three and nine months ended
September 30, 2015
that was recorded as a reduction to
Selling, general and administrative expenses
.
As of
September 30, 2016
and
December 31, 2015
, the Partnership had
$3.1 million
and
$3.8 million
, respectively, due to our General Partner, which has been recorded in
Accrued expenses and other current liabilities
and relates primarily to compensation. This payable is generally settled on a quarterly basis related to the foregoing transactions.
18. Reportable Segments
Our operations are located in the United States and are organized into
three
reportable segments: i) Gathering and Processing, ii) Transmission and iii) Terminals.
Gathering and Processing
Our Gathering and Processing segment provides “wellhead-to-market” services to producers of natural gas and crude oil, which include transporting raw natural gas and crude oil from various receipt points through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs from the natural gas, fractionating NGLs, and selling or delivering pipeline-quality natural gas, crude oil and NGLs to various markets and pipeline systems.
Transmission
Our Transmission segment transports and delivers natural gas from producing wells, receipt points or pipeline interconnects for shippers and other customers, including local distribution companies (“LDCs”), utilities and industrial, commercial and power generation customers.
Terminals
Our Terminals segment provides above-ground storage services at our marine terminals that support various commercial customers, including commodity brokers, refiners and chemical manufacturers to store a range of products, including petroleum products, distillates, chemicals and agricultural products.
These segments are monitored separately by management for performance and are consistent with the Partnership’s internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Gross margin is a performance measure utilized by management to monitor the results of each segment.
The following tables set forth our segment information for the
three and nine months ended
September 30, 2016
and
2015
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, 2016
|
|
|
Gathering
and
Processing
|
|
Transmission
|
|
Terminals
|
|
Total
|
|
Revenue
|
$
|
43,163
|
|
|
$
|
14,368
|
|
|
$
|
6,140
|
|
|
$
|
63,671
|
|
|
Gain (loss) on commodity derivatives, net
|
148
|
|
|
(1
|
)
|
|
—
|
|
|
147
|
|
|
Total revenue
|
43,311
|
|
|
14,367
|
|
|
6,140
|
|
|
63,818
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
Purchases of natural gas, NGLs and condensate
|
23,794
|
|
|
2,288
|
|
|
—
|
|
|
26,082
|
|
|
Direct operating expenses
|
9,924
|
|
|
2,915
|
|
|
3,203
|
|
|
16,042
|
|
|
Selling, general and administrative expenses
|
|
|
|
|
|
|
13,289
|
|
|
Equity compensation expense
|
|
|
|
|
|
|
104
|
|
|
Depreciation, amortization and accretion expense
|
|
|
|
|
|
|
11,018
|
|
|
Total operating expenses
|
|
|
|
|
|
|
66,535
|
|
|
Interest expense
|
|
|
|
|
|
|
(5,156
|
)
|
|
Earnings in unconsolidated affiliates
|
|
|
|
|
|
|
10,993
|
|
|
Income tax expense
|
|
|
|
|
|
|
(441
|
)
|
|
Net income
|
|
|
|
|
|
|
2,679
|
|
|
Less: Net income attributable to noncontrolling interests
|
|
|
|
|
|
|
1,196
|
|
|
Net income attributable to the Partnership
|
|
|
|
|
|
|
$
|
1,483
|
|
|
|
|
|
|
|
|
|
|
|
Segment gross margin (1)
|
$
|
18,821
|
|
|
$
|
12,071
|
|
|
$
|
2,937
|
|
|
$
|
33,829
|
|
_________________________
(1) Segment gross margin for our Gathering and Processing segment consists of total revenue less (i) unrealized gain on commodity derivatives of
$0.3 million
, (ii) construction and operating management agreement (“COMA”) income of
$0.4 million
and (iii) purchases of natural gas, NGLs and condensate.
Segment gross margin for our Transmission segment consists of total revenue less COMA income of less than
$0.1 million
and purchases of natural gas, NGLs and condensate.
Segment gross margin for our Terminals segment consists of total revenue less direct operating expenses.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, 2015
|
|
|
Gathering
and
Processing
|
|
Transmission
|
|
Terminals
|
|
Total
|
|
Revenue
|
$
|
40,103
|
|
|
$
|
9,977
|
|
|
$
|
4,745
|
|
|
$
|
54,825
|
|
|
Gain on commodity derivatives, net
|
816
|
|
|
—
|
|
|
—
|
|
|
816
|
|
|
Total revenue
|
40,919
|
|
|
9,977
|
|
|
4,745
|
|
|
55,641
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
Purchases of natural gas, NGLs and condensate
|
22,055
|
|
|
2,376
|
|
|
—
|
|
|
24,431
|
|
|
Direct operating expenses
|
10,119
|
|
|
3,595
|
|
|
1,614
|
|
|
15,328
|
|
|
Selling, general and administrative expenses
|
|
|
|
|
|
|
7,639
|
|
|
Equity compensation expense
|
|
|
|
|
|
|
574
|
|
|
Depreciation, amortization and accretion expense
|
|
|
|
|
|
|
9,160
|
|
|
Total operating expenses
|
|
|
|
|
|
|
57,132
|
|
|
Loss on sale of assets, net
|
|
|
|
|
|
|
(32
|
)
|
|
Interest expense
|
|
|
|
|
|
|
(3,553
|
)
|
|
Earnings in unconsolidated affiliate
|
|
|
|
|
|
|
1,094
|
|
|
Income tax expense
|
|
|
|
|
|
|
(592
|
)
|
|
Loss from discontinued operations, net of tax
|
|
|
|
|
|
|
(53
|
)
|
|
Net loss
|
|
|
|
|
|
|
(4,627
|
)
|
|
Less: Net income attributable to noncontrolling interests
|
|
|
|
|
|
|
34
|
|
|
Net loss attributable to the Partnership
|
|
|
|
|
|
|
$
|
(4,661
|
)
|
|
|
|
|
|
|
|
|
|
|
Segment gross margin (1)
|
$
|
18,422
|
|
|
$
|
7,581
|
|
|
$
|
3,131
|
|
|
$
|
29,134
|
|
_______________________
(1) Segment gross margin for our Gathering and Processing segment consists of total revenue less (i) unrealized gain on commodity derivatives of
$0.2 million
, (ii) COMA income of
$0.2 million
and (iii) purchases of natural gas, NGLs and condensate.
Segment gross margin for our Transmission segment consists of total revenue less COMA income of less than
$0.1 million
and purchases of natural gas, NGLs and condensate.
Segment gross margin for our Terminals segment consists of total revenue less direct operating expenses.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, 2016
|
|
|
Gathering
and
Processing
|
|
Transmission
|
|
Terminals
|
|
Total
|
|
Revenue
|
$
|
116,091
|
|
|
$
|
33,335
|
|
|
$
|
16,516
|
|
|
$
|
165,942
|
|
|
Loss on commodity derivatives, net
|
(719
|
)
|
|
(3
|
)
|
|
—
|
|
|
(722
|
)
|
|
Total revenue
|
115,372
|
|
|
33,332
|
|
|
16,516
|
|
|
165,220
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
Purchases of natural gas, NGLs and condensate
|
60,206
|
|
|
4,890
|
|
|
—
|
|
|
65,096
|
|
|
Direct operating expenses
|
31,158
|
|
|
9,181
|
|
|
6,415
|
|
|
46,754
|
|
|
Selling, general and administrative expenses
|
|
|
|
|
|
|
33,255
|
|
|
Equity compensation expense
|
|
|
|
|
|
|
2,213
|
|
|
Depreciation, amortization and accretion expense
|
|
|
|
|
|
|
32,015
|
|
|
Total operating expenses
|
|
|
|
|
|
|
179,333
|
|
|
Gain on sale of assets, net
|
|
|
|
|
|
|
90
|
|
|
Interest expense
|
|
|
|
|
|
|
(19,535
|
)
|
|
Earnings in unconsolidated affiliates
|
|
|
|
|
|
|
29,983
|
|
|
Income tax expense
|
|
|
|
|
|
|
(1,301
|
)
|
|
Net loss
|
|
|
|
|
|
|
(4,876
|
)
|
|
Less: Net income attributable to noncontrolling interests
|
|
|
|
|
|
|
2,175
|
|
|
Net loss attributable to the Partnership
|
|
|
|
|
|
|
$
|
(7,051
|
)
|
|
|
|
|
|
|
|
|
|
|
Segment gross margin (1)
|
$
|
55,157
|
|
|
$
|
28,419
|
|
|
$
|
10,101
|
|
|
$
|
93,677
|
|
_______________________
(1)Segment gross margin for our Gathering and Processing segment consists of total revenue less (i) unrealized loss on commodity derivatives of
$(0.3) million
, (ii) COMA income of
$0.3 million
and (iii) purchases of natural gas, NGLs and condensate.
Segment gross margin for our Transmission segment consists of total revenue less COMA income of less than
$0.1 million
and purchases of natural gas, NGLs and condensate.
Segment gross margin for our Terminals segment consists of total revenue less direct operating expenses.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, 2015
|
|
|
Gathering
and
Processing
|
|
Transmission
|
|
Terminals
|
|
Total
|
|
Revenue
|
$
|
138,991
|
|
|
$
|
34,148
|
|
|
$
|
13,346
|
|
|
$
|
186,485
|
|
|
Gain on commodity derivatives, net
|
1,274
|
|
|
—
|
|
|
—
|
|
|
1,274
|
|
|
Total revenue
|
140,265
|
|
|
34,148
|
|
|
13,346
|
|
|
187,759
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
Purchases of natural gas, NGLs and condensate
|
79,645
|
|
|
7,097
|
|
|
—
|
|
|
86,742
|
|
|
Direct operating expenses
|
28,342
|
|
|
10,027
|
|
|
4,793
|
|
|
43,162
|
|
|
Selling, general and administrative expenses
|
|
|
|
|
|
|
20,145
|
|
|
Equity compensation expense
|
|
|
|
|
|
|
2,822
|
|
|
Depreciation, amortization and accretion expense
|
|
|
|
|
|
|
28,099
|
|
|
Total operating expenses
|
|
|
|
|
|
|
180,970
|
|
|
Loss on sale of assets, net
|
|
|
|
|
|
|
(3,010
|
)
|
|
Interest expense
|
|
|
|
|
|
|
(9,719
|
)
|
|
Earnings in unconsolidated affiliates
|
|
|
|
|
|
|
1,265
|
|
|
Income tax expense
|
|
|
|
|
|
|
(1,065
|
)
|
|
Loss from discontinued operations, net of tax
|
|
|
|
|
|
|
(79
|
)
|
|
Net loss
|
|
|
|
|
|
|
(5,819
|
)
|
|
Less: Net income attributable to noncontrolling interests
|
|
|
|
|
|
|
80
|
|
|
Net loss attributable to the Partnership
|
|
|
|
|
|
|
$
|
(5,899
|
)
|
|
|
|
|
|
|
|
|
|
|
Segment gross margin (1)
|
$
|
59,687
|
|
|
$
|
26,975
|
|
|
$
|
8,553
|
|
|
$
|
95,215
|
|
_______________________
(1) Segment gross margin for our Gathering and Processing segment consists of total revenue less (i) unrealized gain on commodity derivatives of
$0.3 million
, (ii) COMA income of
$0.6 million
and (iii) purchases of natural gas, NGLs and condensate.
Segment gross margin for our Transmission segment consists of total revenue less COMA income of
$0.1 million
and purchases of natural gas, NGLs and condensate.
Segment gross margin for our Terminals segment consists of total revenue less direct operating expenses.
A reconciliation of total assets by segment to the amounts included in the condensed consolidated balance sheets follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
December 31,
|
|
|
2016
|
|
2015
|
|
Segment assets:
|
|
|
|
|
Gathering and Processing
|
$
|
593,610
|
|
|
$
|
572,824
|
|
|
Transmission
|
208,370
|
|
|
133,870
|
|
|
Terminals
|
97,201
|
|
|
84,449
|
|
|
Other (1)
|
299,946
|
|
|
100,153
|
|
|
Total assets
|
$
|
1,199,127
|
|
|
$
|
891,296
|
|
_______________________
(1) Other assets not allocable to segments consist of investment in unconsolidated affiliates, corporate leasehold improvements and other assets.
19.
Subsequent Events
Distribution
On October 20, 2016, we announced that the Board of Directors of our General Partner declared a quarterly cash distribution of
$0.4125
per common unit for the quarter ended
September 30, 2016
, or
$1.65
per common unit on an annualized basis. The distribution is expected to be paid on November 14, 2016, to unitholders of record as of the close of business on November 3, 2016.
Interest Rate Swap
On October 20, 2016, we entered into an interest rate swap with a notional amount of
$150 million
at a fixed rate of
1.475%
. The interest rate swap was entered into with a single counterparty and we were not required to post collateral. The interest rate swap is effective beginning January 1, 2018 and will expire December 31, 2022.
JP Energy Partners Merger
On October 23, 2016, the Partnership and our General Partner entered into an Agreement and Plan of Merger (the “LP Merger Agreement”) with JP Energy Partners LP, a Delaware limited partnership (“JPE”), JPE Energy GP II LLC, a Delaware limited liability company and the general partner of JPE (“JPE GP”), Argo Merger Sub, LLC, a Delaware limited liability company and wholly owned subsidiary of the Partnership (“AMID Merger Sub”), and Argo Merger GP Sub, LLC, a Delaware limited liability company and wholly owned subsidiary of the Partnership (“GP Sub”). Upon the terms and subject to the conditions set forth in the LP Merger Agreement, JPE will merge with and into AMID Merger Sub (the “LP Merger”), with JPE continuing its existence under Delaware law as the surviving entity in the LP Merger and an indirect but economically wholly-owned subsidiary of the Partnership. The conflicts committee and the Board of Directors of our General Partner unanimously approved the LP Merger Agreement. The conflicts committee retained independent financial and legal advisors. The board of directors of JPE GP unanimously approved the LP Merger Agreement and agreed to submit the LP Merger Agreement to a vote of JPE unitholders and to recommend that JPE’s unitholders adopt the LP Merger Agreement.
At the effective time of the LP Merger (the “Effective Time”), (i) each common unit of JPE (each, a “JPE Common Unit”) and each subordinated unit of JPE (each, a “JPE Subordinated Unit”) issued and outstanding or deemed issued and outstanding as of immediately prior to the Effective Time (other than JPE Common Units and JPE Subordinated Units held by Lonestar Midstream Holdings, LLC, a Delaware limited liability company, JP Energy Development LP, a Delaware limited partnership, or their respective affiliates (together the “Affiliated Holders”)) will be converted into the right to receive
0.5775
(the “Exchange Ratio”) of a common unit representing limited partner interests in the Partnership (the “Public Unit Consideration”) and (ii) each JPE Common Unit and each JPE Subordinated Unit issued and outstanding or deemed issued and outstanding as of immediately prior to the Effective Time held by the Affiliated Holders will be converted into the right to receive
0.5225
of a common unit (the “Affiliate Unit Consideration” and, together with the Public Unit Consideration, the “LP Merger Consideration”).
In connection with the LP Merger Agreement, on October 23, 2016, our General Partner entered into an Agreement and Plan of Merger (the “GP Merger Agreement”) with JPE GP and Argo GP Sub, LLC, a Delaware limited liability company and wholly owned subsidiary of our General Partner. Upon the terms and subject to the conditions set forth in the GP Merger Agreement, Argo GP Sub, LLC will merge with and into JPE GP (the “GP Merger”), with the separate limited liability company existence of Argo GP Sub, LLC ceasing to exist and JPE GP continuing its existence under Delaware law as the surviving entity in the GP Merger and a wholly owned subsidiary of our General Partner. In connection with the consummation of the GP Merger, GP Sub will be admitted as the sole general partner of JPE and JPE GP will simultaneously cease to be the general partner of JPE. Under the terms of the GP Merger Agreement, all of the JPE GP membership interests issued and outstanding immediately prior to the effective time of the GP Merger will convert into a right to receive Class A Membership Interests (as such term is defined in the Third Amended and Restated Limited Liability Company of American Midstream GP, LLC, dated as of May 2, 2016 (the “AMID GP LLC Agreement”)) in our General Partner, representing a Sharing Percentage (as such term is defined in the AMID GP LLC Agreement) of
18.786%
. Concurrently with the effective time of the GP Merger, the AMID GP LLC Agreement will be amended to reflect the issuance of such Class A Membership Interests.
Additional Delta House Investment
On October 31, 2016, D-Day acquired an additional
6.2%
non-operated direct interest in Delta House for a purchase price of approximately
$48.8 million
which was funded with
$34.5 million
in net proceeds from the issuance of
2,333,333
newly issued Series D convertible preferred units (“Series D Preferred Units) plus
$14.3 million
of additional borrowings under our Credit
Agreement. The Series D Preferred Units were issued at
$15.00
per unit and if any Series D Preferred Units remain outstanding on June 30, 2017, the Partnership will issue a warrant to purchase up to
700,000
common units at an exercise price of
$22.00
per common unit. An affiliate of our General Partner holds the Series D Preferred Units and participates in the related distributions which are to be made in paid-in-kind Series D Units, cash or a combination thereof at the election of the Board of Directors of our General Partner.
The investment in D-Day, together with our
26.3%
interest in Pinto Offshore Holdings, LLC, an entity that owns a
49.0%
non-operated interest in Delta House, results in the Partnership holding a combined
20.1%
non-operated indirect and direct interest in Delta House.
