Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following management’s discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited condensed consolidated financial statements and the related notes thereto included elsewhere in this Quarterly Report on Form 10-Q (“Quarterly Report”) and the audited consolidated financial statements and notes thereto and management’s discussion and analysis of financial condition and results of operations as of and for the year ended
December 31, 2016
included in our Annual Report on Form 10-K (“Annual Report”) that was filed with the Securities and Exchange Commission (“SEC”) on March 28, 2017. This discussion contains forward-looking statements that reflect management’s current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements or as a result of certain factors such as those set forth below under the caption “Cautionary Statement About Forward-Looking Statements.” In addition, please read the Annual Report on Form 10-K for the year ended December 31, 2016 filed by JP Energy Partners, LP, which is not a part of this Quarterly Report or our Annual Report. We acquired JP Energy Partners, LP on March 8, 2017.
Forward-Looking Statements
Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements”. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast,” and other similar words.
All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.
These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Examples of these risks and uncertainties, many of which are beyond our control, include, but are not limited to, the following:
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our ability to generate sufficient cash from operations to pay distributions to unitholders;
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our ability to maintain compliance with financial covenants and ratios in our Credit Agreement (as defined below);
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our ability to timely and successfully identify, consummate and integrate our current and future acquisitions and complete strategic dispositions, including the realization of all anticipated benefits of any such transaction, which otherwise could negatively impact our future financial performance;
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the timing and extent of changes in natural gas, crude oil, NGLs, refined products and other commodity prices, interest rates and demand for our services;
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our ability to access capital to fund growth, including new and amended credit facilities and access to the debt and equity markets, which will depend on general market conditions;
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severe weather and other natural phenomena, including their potential impact on demand for the commodities we sell and the operation of company-owned and third party-owned infrastructure;
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the level of creditworthiness of counterparties to transactions;
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the level and success of natural gas and crude oil drilling around our assets and our success in connecting natural gas and crude oil supplies to our gathering and processing systems;
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the volumes of natural gas and crude oil that we gather, process, transport and store, the throughput volume at our refined products terminals and our NGL sales volumes;
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the fees that we receive for the natural gas, crude oil, refined products and NGL volumes we handle;
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our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks;
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changes in laws and regulations, particularly with regard to taxes, safety, regulation of over-the-counter derivatives market and entities, and protection of the environment;
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our failure or our counterparties’ failure to perform on obligations under commodity derivative and financial derivative contracts;
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the performance of certain of our current and future projects and unconsolidated affiliates that we do not control;
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the demand for natural gas, crude oil, NGL and refined products by the petrochemical, refining or other industries;
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our dependence on a relatively small number of customers for a significant portion of our gross margin;
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general economic, market and business conditions, including industry changes and the impact of consolidations and changes in competition;
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our ability to renew our gathering, processing, transportation and terminal contracts;
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our ability to successfully balance our purchases and sales of natural gas;
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leaks or releases of hydrocarbons into the environment that result in significant costs and liabilities;
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the adequacy of insurance to cover our losses;
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our ability to grow through contributions from affiliates, acquisitions or internal growth projects;
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our management's history and experience with certain aspects of our business and our ability to hire as well as retain qualified personnel to execute our business strategy;
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the cost and effectiveness of our remediation efforts with respect to the material weakness discussed in "Part II. Item 9A. Controls and Procedures" of our Annual Report;
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volatility in the price of our common units;
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security threats such as military campaigns, terrorist attacks, and cybersecurity breaches, against, or otherwise impacting, our facilities and systems; and
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the amount of collateral required to be posted from time to time in our transactions.
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Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report will prove to be accurate. Some of these and additional risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in Part II, Item 1A of this Quarterly Report under the caption “Risk Factors”, Part I, Item 1A of our Annual Report under the caption “Risk Factors” and elsewhere in this Quarterly Report and our Annual Report. The forward-looking statements in this report speak as of the filing date of this report. Except as may be required by applicable securities laws, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.
Overview
We are a growth-oriented Delaware limited partnership that was formed in August 2009 to own, operate, develop and acquire a diversified portfolio of midstream energy assets. We provide critical midstream infrastructure that links producers of natural gas, crude oil, NGLs, condensate and specialty chemicals to numerous intermediate and end-use markets. Through our six financial reporting segments, (i) gas gathering and processing services, (ii) liquid pipelines and services, (iii) natural gas transportation services, (iv) offshore pipelines and services, (v) terminalling services, and (vi) propane marketing services, we engage 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; storing specialty chemical products; and distributing and selling propane and refined products.
Our primary assets are strategically located in some of the most prolific onshore and offshore producing regions and key demand markets in the United States. Our gathering and processing assets are primarily located in (i) the Permian Basin of West Texas, (ii) the Cotton Valley/Haynesville Shale of East Texas, (iii) the Eagle Ford Shale of South Texas, and (iv) offshore in the Gulf of Mexico. Our liquid pipelines, natural gas transportation and offshore pipelines and terminal assets are located in prolific producing regions and key demand markets in Alabama, Louisiana, Mississippi, North Dakota, Texas, Tennessee and in the Port of New Orleans in Louisiana and the Port of Brunswick in Georgia. Additionally, our Propane Marketing Services assets are located in 46 states in the U.S. as well we operate a fleet of NGL gathering and transportation trucks in the Eagle Ford shale and the Permian Basin. See
Recent Developments
regarding the announced sale of our Propane Marketing Services business in July 2017.
We own or have ownership interests in more than 4,100 miles of onshore and offshore natural gas, crude oil, NGL and saltwater pipelines across 17 gathering systems, six interstate pipelines and nine intrastate pipelines; eight natural gas processing plants; four fractionation facilities; an offshore semisubmersible floating production system with nameplate processing capacity of 80 MMBbl/d of crude oil and 200 MMcf/d of natural gas; six marine terminal sites with approximately 6.7 MMBbls of above-ground aggregate storage capacity for petroleum products, distillates, chemicals and agricultural products; and 97 transportation trucks.
A portion of our cash flow is derived from our investments in unconsolidated affiliates, including a 49.7% operated interest in Destin, a natural gas pipeline; a 20.1% non-operated interest in the Class A Units of Delta House, which is a floating production system platform and related pipeline infrastructure; a 16.7% non-operated interest in Tri-States, an NGL pipeline; a 66.7% operated interest in Okeanos, a natural gas pipeline; a 25.3% non-operated interest in Wilprise, a NGL pipeline; and a 66.7% non-operated interest in MPOG, a crude oil gathering and processing system.
Recent Developments
Our business objectives continue to focus on maintaining stable cash flows from our existing assets and executing on growth opportunities to increase our long-term cash flows. We believe the key elements to stable cash flows are the diversity of our asset portfolio and our fee-based business which represents a significant portion of our estimated margins, the objective of which is to protect against downside risk in our cash flows.
On July 14, 2017, we entered into Amendment No. 5 to our Fifth Amended and Restated Partnership Agreement (as amended, the “Partnership Agreement”). It was provided previously that if any of the Series D Units remain outstanding on June 30, 2017 (the “ Series D Determination Date”), we will issue the holder of the Series D Units a warrant (the “Series D Warrant”) to purchase 700,000 common units representing limited partnership interests with an exercise price of $22.00 per common unit. The Partnership Agreement has extended the Series D Determination Date to August 31, 2017.
On July 21, 2017, we entered into a Membership Interest Purchase Agreement with SHV Energy N.V., pursuant to which we agreed to sell 100% of our Propane Marketing Services business, including Pinnacle Propane’s 40 service locations, Pinnacle Propane Express’ cylinder exchange business and related logistic assets, and the Alliant Gas utility system to SHV Energy N.V., for $170 million in cash, plus balance sheet cash at closing, less the repayment of all indebtedness and transaction costs, and subject to working capital adjustments. The transaction is expected to close in the third quarter of 2017.
Financial Highlights
Financial highlights for the
three months ended June 30, 2017
, include the following:
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Net loss attributable to the Partnership increased to
$29.2 million
, as compared to net loss of
$10.4 million
in the same period in 2016, primarily due to an increase in corporate expenses relating to transition costs and a significant increase in interest expenses associated with the JPE Acquisition (as defined below), partially offset by a large increase in earnings from unconsolidated affiliates;
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Earnings in unconsolidated affiliates were
$17.6 million
, an increase of
$5.9 million
as compared to the same period in 2016, primarily due to the additional Delta House investments in the second quarter and in the fourth quarter of 2016 and us having a full quarter of earnings in 2017 relating to the Emerald Transactions;
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Segment gross margin amounted to
$79.3 million
, or a decrease of
$1.8 million
as compared to the same period in 2016, primarily due to higher segment gross margin in our Offshore Pipelines and Services segment, offset by a large decrease in the segment gross margin of our Propane Marketing Services segment;
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Adjusted EBITDA decreased to
$44.5 million
, or a decrease of
18.2%
as compared to the same period in 2016, primarily due to a larger loss in 2017, and lower distributions from our unconsolidated affiliates in 2017; and
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We distributed
$21.4 million
to our common unitholders, or
$0.4125
per common unit, the 24th consecutive distribution since our initial public offering.
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Operational highlights for the
three months ended June 30, 2017
, include the following:
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Contracted capacity for our Terminalling Services segment averaged 5,139,367 Bbls, representing a 2.4% increase compared to the same period in
2016
;
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Average condensate production totaled
79.8
Mgal/d, representing a 4.5Mgal/d or
5%
decrease
compared to the same period in
2016
;
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Average gross NGL production totaled
398.8
Mgal/d, representing a
135.5
Mgal/d or
51%
increase
compared to the same period in
2016
;
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Throughput volumes attributable to the Natural Gas Transportation Services and Offshore Pipelines and Services segments totaled
729
MMcf/d, representing a
152
MMcf/d or
17%
decrease compared to the same period in
2016
;
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Throughput volumes attributable to the Liquid Pipelines and Services segment totaled
32,957
Bbls/d, representing a 1,867 Bbls/d or 6% increase compared to the same period in 2016;
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NGL and refined product sales attributable to our Propane Marketing Services segment totaled
151.6
Mgal/d, representing a decrease of 12.7 Mgal/d or 8% compared to the same period in 2016, mainly due to warmer than normal temperatures during the winter; and
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The percentage of gross margin generated from fee based, fixed margin, firm and interruptible transportation contracts and firm storage contracts (excluding propane) was
93.2%
representing a decrease of
8.8%
as compared to the same period in 2016.
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JPE Acquisition
On March 8, 2017, we completed the acquisition of JP Energy Partners LP (“JPE”), an entity controlled by affiliates of ArcLight Capital Partners, LLC (“ArcLight”), in a unit-for-unit merger (the “JPE Acquisition”). In connection with the transaction, each JPE common or subordinated unit held by investors not affiliated with ArcLight was converted into the right to receive 0.5775 of a Partnership common unit, and each JPE common or subordinated unit held by ArcLight affiliates was converted into the right to receive 0.5225 of a Partnership common unit. We issued a total of 20.2 million of common units to complete the acquisition, including 9.8 million common units to ArcLight affiliates.
As both we and JPE were controlled by ArcLight affiliates, the acquisition represented a transaction among entities under common control. Although we are the legal acquirer, JPE was considered the acquirer for accounting purposes as ArcLight obtained control of JPE prior to obtaining control of us on April 15, 2013. As a result, we adjusted our historical financial statements to reflect ArcLight’s acquisition cost basis back to April 15, 2013. In addition, the accompanying financial statements and related notes have been retrospectively adjusted to include the historical results of JPE prior to the effective date of the JPE acquisition. The accompanying financial statements and related notes present the combined financial position, results of operations, cash flows and equity of JPE at historical cost.
JPE owns, operates and develops a diversified portfolio of midstream energy assets with
three
business segments (i) crude oil pipelines and storage, (ii) refined products terminals and storage, and (iii) NGL distribution and sales, which together provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs, in the United States.
Third Amendment to Partnership Agreement
On March 8, 2017, we also executed Amendment No. 3 to our Fifth Amended and Restated Partnership Agreement (as amended, the “Partnership Agreement”), which amends the distribution payment terms of our outstanding Series A Preferred Units to provide for the payment of a number of Series A payment-in-kind (“PIK”) preferred units for the quarter (the “Series A Preferred Quarterly Distribution”) in which the JPE Acquisition was consummated (which is the quarter ended March 31, 2017) and each quarter
thereafter equal to the quotient of (i) the greater of (a) $0.4125 and (b) the "Series A Distribution Amount", as such term is defined in the Partnership Agreement, divided by (ii) the “Series A Adjusted Issue Price,” as such term is defined in the Partnership Agreement. However, in our General Partner’s discretion, which determination shall be made prior to the record date for the relevant quarter, the Series A Preferred Quarterly Distribution may be paid as a combination of (x) an amount in cash up to the greater of (1) $0.4125 and (2) the Series A Distribution Amount, and (y) a number of Series A Preferred Units equal to the quotient of (a) the remainder of (i) the greater of (I) $0.4125 and (II) the Series A Distribution Amount less (ii) the amount of cash paid pursuant to clause (x), divided by (b) the Series A Adjusted Issue Price. This calculation results in a reduced Series A Preferred Quarterly Distribution, which was previously calculated under the Partnership Agreement using $0.50 in place of $0.4125 in the preceding calculations.
Second Amended and Restated Credit Agreement
On March 8, 2017, we and American Midstream, LLC, along with other of our subsidiaries (collectively, the “Borrowers”) entered into a Second Amended and Restated Credit Agreement with Bank of America, N.A., as Administrative Agent, Collateral Agent and L/C Issuer, Wells Fargo Bank, National Association, as Syndication Agent, and other lenders (the “Second Amended Credit Agreement”). By entering into the Second Amended Credit Agreement, we amended our existing credit facility to increase our borrowing capacity thereunder from $750 million to $900 million and to provide for an accordion feature that will permit, subject
to the customary conditions, the borrowing capacity under the facility to be increased to a maximum of $1.1 billion. The $900 million in lending commitments under the Second Amended Credit Agreement includes a $30 million sublimit for borrowings by the Blackwater Borrower and a $100 million sublimit for standby letters of credit, which was increased in this Second Amended Credit Agreement from $50 million. The Second Amended Credit Agreement matures on September 5, 2019. The Second Amended Credit Agreement facilitates the joinder to the credit facility of certain surviving entities from the JPE Acquisition (the "JPE Entities") and adjusts certain covenants, representations and warranties under the credit facility to support the JPE Entities. All obligations under the Second Amended Credit Agreement and the guarantees of those obligations are secured, subject to certain exceptions, by a first-priority lien on and security interest in substantially all of the Borrowers’ assets and the assets of all, subject to certain exceptions, existing and future subsidiaries and all of the capital stock of the Partnership’s existing and future subsidiaries.
When we use the term “revolving credit facility” or “Credit Agreement,” we are referring to our First Amended and Restated Credit Facility and to our Second Amended and Restated Credit Facility, as the context may require.
8.50% Senior Unsecured Notes
On December 28, 2016, we and American Midstream Finance Corporation, our wholly owned subsidiary (together with the Partnership, the “Issuers”) completed the issuance and sale of $300 million in aggregate principal amount of senior notes due 2021 (the "8.50% Senior Notes"). Wells Fargo Securities, LLC served as the representative of the initial purchasers, which included Merrill Lynch, Pierce, Fenner & Smith Incorporated, RBC Capital Markets, LLC, Citigroup Global Markets Inc., SunTrust Robinson Humphrey, Inc., Natixis Securities Americas LLC, ABN AMRO Securities (USA) LLC, Capital One Securities, Inc., Deutsche Bank Securities Inc., BNP Paribas Securities Corp., BMO Capital Markets Corp., Santander Investment Securities Inc. and BBVA Securities Inc. The 8.50% Senior Notes rank equal in right of payment with all existing and future senior indebtedness of the Issuers, and senior in right of payment to any future subordinated indebtedness of the Issuers. The 8.50% Senior Notes were issued at par and provided net proceeds of approximately $294.0 million, after deducting the initial purchasers' discount of $6.0 million. This amount was deposited into escrow pending completion of the JPE Acquisition and is included in
Restricted cash-long term
on the Partnership's consolidated balance sheet as of December 31, 2016. The Partnership also incurred $2.7 million of direct issuance costs resulting in net proceeds related to the 8.50% Senior Notes of $291.3 million. The notes were offered and sold to qualified institutional buyers in the United States pursuant to Rule 144A under the Securities Act, and to persons, other than U.S. persons, outside the United States pursuant to Regulation S under the Securities Act.
Upon the closing of the JPE Acquisition and the satisfaction of other related conditions, the restricted cash was released from escrow on March 8, 2017. The Partnership used the net proceeds to repay and terminate JPE's revolving credit facility and to reduce borrowings under the Credit Agreement.
Commodity Prices
Average daily prices for NYMEX West Texas Intermediate crude oil ranged from a high of $54.45 per barrel to a low of $42.53 per barrel from January 1, 2017 through
July 31, 2017
. Average daily prices for NYMEX Henry Hub natural gas ranged from a high of $3.71 per MMBtu to a low of $2.44 per MMBtu from January 1, 2017 through
July 31, 2017
.
Fluctuations in energy prices can greatly affect the development of new crude oil and natural gas reserves. Further declines in commodity prices of crude oil and natural gas could have a negative impact on exploration, development and production activity, and, if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to continued or further reduced utilization of our assets. We are unable to predict future potential movements in the market price for natural gas, crude oil and NGLs and thus, cannot predict the ultimate impact of commodity prices on our operations. Should commodity prices continue to remain depressed as they were in 2015 and in 2016, this could lead to reduced profitability and may impact our liquidity and compliance with financial covenants and ratios under our Credit Agreement, which include a maximum total leverage ratio which is measured on a quarterly basis. Reduced profitability could adversely affect our operations, our ability to pay distributions to our unitholders, and may result in future impairments of our long-lived assets, goodwill, and intangible assets.
Capital Markets
Volatility in the capital markets continues to impact our operations in multiple ways, including limiting our producers’ ability to finance their drilling and workover programs and limiting our ability to fund drop downs, organic growth projects and acquisitions.
Our Operations
We manage our business and analyze and report our results of operations through six reportable segments:
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Gas Gathering and Processing Services
. Our Gas Gathering and Processing Services segment provides “wellhead-to-market” services to producers of natural gas and natural gas liquids, which include transporting raw natural gas 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 and NGLs to various markets and pipeline systems.
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Liquid Pipelines and Services
. Our Liquid Pipelines and Services segment provides transportation, purchase and sales of crude oil from various receipt points including lease automatic customer transfer (“LACT”) facilities and deliveries to various markets.
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Natural Gas Transportation Services
. Our Natural Gas Transportation Services segment transports and delivers natural gas from producing wells, receipt points or pipeline interconnects for shippers and other customers, which include local distribution companies (“LDCs”), utilities and industrial, commercial and power generation customers.
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Offshore Pipelines and Services
. Our Offshore Pipelines and Services segment gathers and transports natural gas and crude oil from various receipt points to other pipeline interconnects, onshore facilities and other delivery points.
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Terminalling Services
. Our Terminalling Services segment provides above-ground leasable storage operations at our marine terminals that support various commercial customers, including commodity brokers, refiners and chemical manufacturers to store a range of products and also includes crude oil storage in Cushing, Oklahoma and refined products terminals in Texas and Arkansas.
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Propane Marketing Services
. Our Propane Marketing Services segment gathers, transports and sells natural gas liquids (NGLs). This is accomplished through cylinder tank exchange, sales through retail, commercial and wholesale distribution and through a fleet of trucks operating in the Eagle Ford and Permian basin areas.
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Gas Gathering and Processing Services Segment
Results of operations from the Gas Gathering and Processing Services segment are determined primarily by the volumes of natural gas we gather, process and fractionate, the commercial terms in our current contract portfolio and natural gas, crude oil, NGL and condensate prices. We gather and process natural gas primarily pursuant to the following arrangements:
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Fee-Based Arrangements.
Under these arrangements, we generally are paid a fixed fee for gathering, processing and transporting natural gas.
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Fixed-Margin Arrangements.
Under these arrangements, we purchase natural gas and off-spec condensate from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and
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simultaneously sell an identical volume of natural gas or off-spec condensate at delivery points on our systems at the same, undiscounted index price. By entering into back-to-back purchases and sales of natural gas or off-spec condensate, we are able to lock in a fixed margin on these transactions. We view the segment gross margin earned under our fixed-margin arrangements to be economically equivalent to the fee earned in our fee-based arrangements.
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Percent-of-Proceeds Arrangements (“POP”).
Under these arrangements, we generally gather raw natural gas from producers at the wellhead or other supply points, transport it through our gathering system, process it and sell the residue natural gas, NGLs and condensate at market prices. Where we provide processing services at the processing plants that we own, or obtain processing services for our own account in connection with our elective processing arrangements, we generally retain and sell a percentage of the residue natural gas and resulting NGLs. However, we also have contracts under which we retain a percentage of the resulting NGLs and do not retain a percentage of residue natural gas. Our POP arrangements also often contain a fee-based component.
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Gross margin earned under fee-based and fixed-margin arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. However, a sustained decline in commodity prices could result in a decline in throughput volumes from producers and, thus, a decrease in our fee-based and fixed-margin gross margin. These arrangements provide stable cash flows, but upside in higher commodity-price environments is limited to an increase in throughput volumes from producers. Under our typical POP arrangement, our gross margin is directly impacted by the commodity prices we realize on our share of natural gas and NGLs received as compensation for processing raw natural gas. However, our POP arrangements often contain a fee-based component, which helps to mitigate the degree of commodity-price volatility we could experience under these arrangements. We further seek to mitigate our exposure to commodity price risk through our hedging program. See the information set forth in Part I, Item 3 of this Quarterly Report under the caption “ — Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”
Liquid Pipelines and Services Segment
Results of operations from the Liquid Pipelines and Services segment are determined by the volumes of crude oil transported on the interstate and intrastate pipelines we own. Tariffs associated with our Bakken system are regulated by FERC for volumes gathered via pipeline and trucked to the AMID Truck facility in Watford City, North Dakota. Volumes transported on our Silver Dollar system are underpinned by long-term, fee-based contracts. Our transportation arrangements are further described below:
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Firm Transportation Arrangements.
Our obligation to provide firm transportation service means that we are obligated to transport crude oil nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not the shipper utilizes the capacity. In most cases, the shipper also pays a variable-use charge with respect to quantities actually transported by us.
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Uncommitted Shipper Arrangements.
Our obligation to provide interruptible transportation service means that we are only obligated to transport crude oil nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge but pays a variable-use charge for quantities actually shipped.
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Fee-Based Arrangements.
Under these arrangements our operations are underpinned by long-term, fee-based contracts with leading producers in the Midland Basin. Some of these contracts also have minimum volume commitments as well as some have acreage dedications.
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Buy-Sell Arrangements.
We enter into outright purchase and sales contracts as well as buy/sell contracts with counterparties, under which contracts we gather and transport different types of crude oil and eventually sell the crude oil to either the same counterparty or different counterparties. We account for such revenue arrangements on a gross basis. Occasionally, we enter into crude oil inventory exchange arrangements with the same counterparty which the purchase and sale of inventory are considered in contemplation of each other. Revenues from such inventory exchange arrangements are recorded on a net basis.
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Natural Gas Transportation Services Segment
Results of operations from the Natural Gas Transportation Services segment are determined by capacity reservation fees from firm and interruptible transportation contracts and the volumes of natural gas transported on the interstate and intrastate pipelines we own pursuant to interruptible transportation or fixed-margin contracts. Our transportation arrangements are further described below:
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Firm Transportation Arrangements.
Our obligation to provide firm transportation service means that we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not the shipper utilizes the capacity. In most cases, the shipper also pays a variable-use charge with respect to quantities actually transported by us.
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Interruptible Transportation Arrangements.
Our obligation to provide interruptible transportation service means that we are only obligated to transport natural gas nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge but pays a variable-use charge for quantities actually shipped.
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Fixed-Margin Arrangements.
Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same undiscounted index price. We view fixed-margin arrangements to be economically equivalent to our interruptible transportation arrangements.
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Offshore Pipelines and Services
Results of operations from the Offshore Pipelines and Services segment are determined by capacity reservation fees from firm and interruptible transportation contracts and the volumes of natural gas transported on the interstate and intrastate pipelines we own pursuant to interruptible transportation or fixed-margin contracts. Our transportation arrangements are further described below:
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Firm Transportation Arrangements.
Our obligation to provide firm transportation service means that we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not the shipper utilizes the capacity. In most cases, the shipper also pays a variable-use charge with respect to quantities actually transported by us.
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Interruptible Transportation Arrangements.
Our obligation to provide interruptible transportation service means that we are only obligated to transport natural gas nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge but pays a variable-use charge for quantities actually shipped.
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Fixed-Margin Arrangements.
Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same undiscounted index price. We view fixed-margin arrangements to be economically equivalent to our interruptible transportation arrangements.
|
Terminalling Services Segment
Our Terminalling Services segment provides above-ground leasable 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. We generally receive fee-based compensation on guaranteed firm storage contracts, throughput fees charged to our customers when their products are either received or disbursed and other fee-based charges associated with ancillary services provided to our customers, such as excess throughput, truck weighing, etc. Our firm storage contracts are typically multi-year contracts with renewal options. Our refined products terminals have butane blending capabilities.
Propane Marketing Services Segment
Our Propane Marketing Services segment consists of (i) portable cylinder tank exchange, (ii) NGL sales through our retail, commercial and wholesale distribution business, and (iii) NGL gathering and transportation business. Currently, the cylinder exchange network covers 46 states through a network of approximately 20,000 locations, which includes grocery chains, pharmacies, convenience stores and hardware stores. Additionally, in seven states in the southwest region of the U.S., we sell NGLs to retailers, wholesalers, industrial end-users and commercial and residential customers. We also own a fleet of NGL gathering and transportation operations trucks operating in the Eagle Ford shale and the Permian Basin.
Contract Mix
For the
three months ended June 30, 2017
and
2016
,
$56.5 million
and
$51.7 million
, or
93.2%
and
92.4%
, respectively, of our gross margin (excluding propane) was generated from fee-based, fixed margin, firm and interruptible transportation contracts and firm storage contracts. Set forth below is a table summarizing our average contract mix relative to segment gross margin for the
three months ended June 30, 2017
and
2016
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2017
|
|
Three months ended June 30, 2016
|
|
|
Segment
Gross
Margin
|
|
Percent of
Segment
Gross Margin
|
|
Segment
Gross
Margin
|
|
Percent of
Segment
Gross Margin
|
Gas Gathering and Processing Services
|
|
|
|
|
|
|
|
|
Fee-based
|
|
$
|
4,302
|
|
|
34
|
%
|
|
$
|
7,469
|
|
|
56
|
%
|
Fixed margin
|
|
4,301
|
|
|
34
|
%
|
|
1,600
|
|
|
12
|
%
|
Percent-of-proceeds
|
|
4,048
|
|
|
32
|
%
|
|
4,268
|
|
|
32
|
%
|
Total
|
|
$
|
12,651
|
|
|
100
|
%
|
|
$
|
13,337
|
|
|
100
|
%
|
Liquid Pipelines and Services
|
|
|
|
|
|
|
|
|
Fee-based
|
|
$
|
5,012
|
|
|
75
|
%
|
|
$
|
5,282
|
|
|
56
|
%
|
Fixed margin
|
|
1,671
|
|
|
25
|
%
|
|
4,150
|
|
|
44
|
%
|
Total
|
|
$
|
6,683
|
|
|
100
|
%
|
|
$
|
9,432
|
|
|
100
|
%
|
Natural Gas Transportation Services
|
|
|
|
|
|
|
|
|
Firm transportation
|
|
$
|
3,266
|
|
|
58
|
%
|
|
$
|
3,266
|
|
|
85
|
%
|
Interruptible transportation
|
|
845
|
|
|
15
|
%
|
|
961
|
|
|
25
|
%
|
Fee-based
|
|
394
|
|
|
7
|
%
|
|
269
|
|
|
7
|
%
|
Fixed margin
|
|
1,126
|
|
|
20
|
%
|
|
(653
|
)
|
|
(17
|
)%
|
Total
|
|
$
|
5,631
|
|
|
100
|
%
|
|
$
|
3,843
|
|
|
100
|
%
|
Offshore Pipelines and Services
|
|
|
|
|
|
|
|
|
Interruptible transportation
|
|
8,199
|
|
|
32
|
%
|
|
10,279
|
|
|
50
|
%
|
Fee-based
|
|
16,912
|
|
|
66
|
%
|
|
9,662
|
|
|
47
|
%
|
Fixed margin
|
|
512
|
|
|
2
|
%
|
|
617
|
|
|
3
|
%
|
Total
|
|
$
|
25,623
|
|
|
100
|
%
|
|
$
|
20,558
|
|
|
100
|
%
|
Terminalling Services
|
|
|
|
|
|
|
|
|
Firm storage
|
|
$
|
6,133
|
|
|
57
|
%
|
|
$
|
7,647
|
|
|
66
|
%
|
Refined products distribution
|
|
753
|
|
|
7
|
%
|
|
2,781
|
|
|
24
|
%
|
Fee-based
|
|
3,874
|
|
|
36
|
%
|
|
1,158
|
|
|
10
|
%
|
Total
|
|
$
|
10,760
|
|
|
100
|
%
|
|
$
|
11,586
|
|
|
100
|
%
|
Propane Marketing Services
|
|
|
|
|
|
|
|
|
Distribution
|
|
$
|
17,952
|
|
|
100
|
%
|
|
$
|
22,316
|
|
|
100
|
%
|
Total
|
|
$
|
17,952
|
|
|
100
|
%
|
|
$
|
22,316
|
|
|
100
|
%
|
Cash distributions received from our unconsolidated affiliates amounted to
$15.9 million
and
$26.6 million
for the
three months ended June 30, 2017
and
2016
, respectively. Cash distributions derived from our unconsolidated affiliates are primarily generated from fee-based gathering and processing arrangements.
For the
six months ended June 30, 2017
and
2016
,
$111.6 million
and
$95.1 million
, or
92.5%
and
93.6%
, respectively, of our gross margin (excluding propane) was generated from fee-based, fixed margin, firm and interruptible transportation contracts and firm storage contracts. Set forth below is a table summarizing our average contract mix relative to segment gross margin for the periods presented (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2017
|
|
Six months ended June 30, 2016
|
|
|
Segment
Gross
Margin
|
|
Percent of
Segment
Gross Margin
|
|
Segment
Gross
Margin
|
|
Percent of
Segment
Gross Margin
|
Gas Gathering and Processing Services
|
|
|
|
|
|
|
|
|
Fee-based
|
|
$
|
8,605
|
|
|
36
|
%
|
|
$
|
15,224
|
|
|
61
|
%
|
Fixed margin
|
|
6,214
|
|
|
26
|
%
|
|
3,244
|
|
|
13
|
%
|
Percent-of-proceeds
|
|
9,083
|
|
|
38
|
%
|
|
6,489
|
|
|
26
|
%
|
Total
|
|
$
|
23,902
|
|
|
100
|
%
|
|
$
|
24,957
|
|
|
100
|
%
|
Liquid Pipelines and Services
|
|
|
|
|
|
|
|
|
Fee-based
|
|
$
|
11,048
|
|
|
84
|
%
|
|
$
|
10,087
|
|
|
66
|
%
|
Fixed margin
|
|
2,104
|
|
|
16
|
%
|
|
5,197
|
|
|
34
|
%
|
Total
|
|
$
|
13,152
|
|
|
100
|
%
|
|
$
|
15,284
|
|
|
100
|
%
|
Natural Gas Transportation Services
|
|
|
|
|
|
|
|
|
Firm transportation
|
|
$
|
7,285
|
|
|
62
|
%
|
|
$
|
7,055
|
|
|
75
|
%
|
Interruptible transportation
|
|
1,998
|
|
|
17
|
%
|
|
2,163
|
|
|
23
|
%
|
Fee-based
|
|
939
|
|
|
8
|
%
|
|
564
|
|
|
6
|
%
|
Fixed margin
|
|
1,528
|
|
|
13
|
%
|
|
(376
|
)
|
|
(4
|
)%
|
Total
|
|
$
|
11,750
|
|
|
100
|
%
|
|
$
|
9,406
|
|
|
100
|
%
|
Offshore Pipelines and Services
|
|
|
|
|
|
|
|
|
Firm transportation
|
|
$
|
1,029
|
|
|
2
|
%
|
|
$
|
338
|
|
|
1
|
%
|
Interruptible transportation
|
|
21,085
|
|
|
41
|
%
|
|
21,644
|
|
|
64
|
%
|
Fee-based
|
|
28,799
|
|
|
56
|
%
|
|
10,822
|
|
|
32
|
%
|
Fixed margin
|
|
513
|
|
|
1
|
%
|
|
1,015
|
|
|
3
|
%
|
Total
|
|
$
|
51,426
|
|
|
100
|
%
|
|
$
|
33,819
|
|
|
100
|
%
|
Terminalling Services
|
|
|
|
|
|
|
|
|
Firm storage
|
|
$
|
13,372
|
|
|
61
|
%
|
|
$
|
10,936
|
|
|
52
|
%
|
Refined products distribution
|
|
438
|
|
|
2
|
%
|
|
2,523
|
|
|
12
|
%
|
Fee-based
|
|
8,110
|
|
|
37
|
%
|
|
7,571
|
|
|
36
|
%
|
Total
|
|
$
|
21,920
|
|
|
100
|
%
|
|
$
|
21,030
|
|
|
100
|
%
|
Propane Marketing Services
|
|
|
|
|
|
|
|
|
Distribution
|
|
$
|
37,254
|
|
|
100
|
%
|
|
$
|
50,621
|
|
|
100
|
%
|
Total
|
|
$
|
37,254
|
|
|
100
|
%
|
|
$
|
50,621
|
|
|
100
|
%
|
Cash distributions received from our unconsolidated affiliates amounted to
$38.4 million
and $40.1 million for the six months ended June 30, 2017 and 2016, respectively. Cash distributions derived from our unconsolidated affiliates are primarily generated from fee-based gathering and processing arrangements.
How We Evaluate Our Operations
Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on at least a monthly basis for consistency and trend analysis. These metrics include throughput volumes, storage utilization, segment gross margin, gross margin, operating margin, direct operating expenses on a segment basis, and Adjusted EBITDA on a company-wide basis.
Throughput Volumes
In our Gas Gathering and Processing Services segment, we must continually obtain new supplies of natural gas, NGLs and condensate to maintain or increase throughput volumes on our systems. Our ability to maintain or increase existing volumes of natural gas, NGLs and condensate is impacted by i) the level of work-overs or recompletions of existing connected wells and successful drilling activity of our significant producers in areas currently dedicated to or near our gathering systems, ii) our ability to compete for volumes from successful new wells in the areas in which we operate, iii) our ability to obtain natural gas, crude oil, NGLs and condensate that has been released from other commitments and iv) the volume of natural gas, NGLs and condensate that we purchase from connected systems. We actively monitor producer activity in the areas served by our gathering and processing systems to maintain current throughput volumes and pursue new supply opportunities.
In our Liquid Pipelines and Services segment, the amount of revenue we generate from our crude oil pipelines business depends primarily on throughput volumes. We generate a portion of our crude oil pipeline revenues through long-term contracts containing acreage dedications or minimum volume commitments. Throughput volumes on our pipeline system are affected primarily by the supply of crude oil in the market served by our assets. The revenue generated from our crude oil supply and logistics business depends on the volume of crude oil we purchase from producers, aggregators and traders and then sell to producers, traders and refiners as well as the volumes of crude oil that we gather and transport. The volume of our crude oil supply and logistics activities and the volumes transported by our crude oil gathering and transportation trucks are affected by the supply of crude oil in the markets served directly or indirectly by our assets. Accordingly, we actively monitor producer activity in the areas served by our crude oil supply and logistics business and other producing areas in the United States to compete for volumes from crude oil producers. Revenues in this business are also impacted by changes in the market price of commodities that we pass through to our customers.
In our Natural Gas Transportation Services and Offshore Pipelines and Services segments, the majority of our segment gross margin is generated by firm capacity reservation charges and interruptible transportation services from throughput volumes on our interstate and intrastate pipelines. Substantially all of the segment gross margin is generated under contracts with shippers, including producers, industrial companies, LDCs and marketers, for firm and interruptible natural gas transportation on our pipelines. We routinely monitor natural gas market activities in the areas served by our transmission systems to maintain current throughput volumes and pursue new shipper opportunities.
In our Terminalling Services segment, we receive fee-based compensation on guaranteed firm storage contracts, throughput fees charged to our customers when their products are either received or disbursed, and other operational charges associated with ancillary services provided to our customers, such as excess throughput, steam heating, and truck weighing at our marine terminals. The amount of revenue we generate from our refined products terminals depends primarily on the volume of refined products that we handle. These volumes are affected primarily by the supply of and demand for refined products in the markets served directly or indirectly by our refined products terminals. Our refined products terminals have butane blending capabilities. The volume of crude oil stored at our crude oil storage facility in Cushing, Oklahoma has no impact on the revenue generated by our crude oil storage business because we receive a fixed monthly fee per barrel of shell capacity that is not contingent on the usage of our storage tanks.
In our Propane Marketing Services segment the amount of revenue we generate depends on the gallons of NGLs we sell through our cylinder exchange and NGL sales businesses. In addition, our NGL transportation operations generate revenue based on the number of gallons of NGLs we gather and the distance we transport those gallons for our customers. Revenues in this segment are also impacted by changes in the market price of commodities that we pass through to our customers.
Storage Utilization
Storage utilization is a metric that we use to evaluate the performance of our Terminalling Services segment. We define storage utilization as the percentage of the contracted capacity in barrels compared to the design capacity of the tank.
Segment Gross Margin and Gross Margin
Segment gross margin and gross margin are metrics that we use to evaluate our performance.
We define segment gross margin in our Gas Gathering and Processing Services segment as total revenue plus unconsolidated affiliate earnings less unrealized gains or plus unrealized losses on commodity derivatives, construction and operating management agreement income and the cost of natural gas, and NGLs and condensate purchased.
We define segment gross margin in our Liquid Pipelines and Services segment as total revenue plus unconsolidated affiliate earnings less unrealized gains or plus unrealized losses on commodity derivatives and the cost of crude oil purchased in connection with fixed-margin arrangements. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk.
We define segment gross margin in our Natural Gas Transportation Services segment as total revenue plus unconsolidated affiliate earnings less the cost of natural gas purchased in connection with fixed-margin arrangements. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk.
We define segment gross margin in our Offshore Pipelines and Services segment as total revenue plus unconsolidated affiliate earnings less the cost of natural gas purchased in connection with fixed-margin arrangements. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk.
We define segment gross margin in our Terminalling Services segment as total revenue less direct operating expense which includes direct labor, general materials and supplies and direct overhead.
We define segment gross margin in our Propane Marketing Services segment as total revenue less purchases of natural gas, NGLs and condensate excluding non-cash charges such as non-cash unrealized gains or losses on commodity derivatives.
Gross margin is a supplemental non-GAAP financial measure that we use to evaluate our performance. We define gross margin as the sum of the segment gross margins for our Gas Gathering and Processing Services, Liquid Pipelines and Services, Natural Gas Transportation Services, Offshore Pipelines and Services, Terminalling Services and Propane Marketing Services segments. The GAAP measure most directly comparable to gross margin is Net income (loss) attributable to the Partnership. For a reconciliation of gross margin to net income (loss), see “Non-GAAP Financial Measures” below.
Operating Margin
Operating margin is a supplemental non-GAAP financial metric that we use to evaluate our performance. We define operating margin as total segment gross margin less other direct operating expenses. The GAAP measure most directly comparable to operating margin is net income (loss) attributable to the Partnership. For a reconciliation of Operating Margin to net income (loss), see “- Non-GAAP Financial Measures.”
Direct Operating Expenses
Our management seeks to maximize the profitability of our operations in part by minimizing direct operating expenses without sacrificing safety or the environment. Direct labor costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities, lost and unaccounted for gas, and contract services comprise the most significant portion of our operating expenses. These expenses are relatively stable and largely independent of throughput volumes through our systems but may fluctuate depending on the activities performed during a specific period.
Adjusted EBITDA
Adjusted EBITDA is a supplemental non-GAAP financial measure used by our management and external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess: the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; the ability of our assets to generate cash flow to make cash distributions to our unitholders and our General Partner; our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.
We define Adjusted EBITDA as net income (loss) attributable to the Partnership, plus interest expense, income tax expense, depreciation, amortization and accretion expense attributable to the Partnership, debt issuance costs paid during the period, distributions from investments in unconsolidated affiliates, transaction expenses primarily associated with our JPE Acquisition, Delta House acquisition, certain non-cash charges such as non-cash equity compensation expense, unrealized (gains) losses on derivatives and selected charges that are unusual, less construction and operating management agreement income, other post-employment benefits plan net periodic benefit, earnings in unconsolidated affiliates, gains (losses) on the sale of assets, net, and selected gains that are unusual. The GAAP measure most directly comparable to our performance measure Adjusted EBITDA is net income (loss) attributable to the Partnership. For a reconciliation of Adjusted EBITDA to net income (loss), see “Non-GAAP Financial Measures” below.
Non-GAAP Financial Measures
Gross margin, segment gross margin, operating margin and Adjusted EBITDA are performance measures that are non-GAAP financial measures. Each has important limitations as an analytical tool because they exclude some, but not all, items that affect the most directly comparable GAAP financial measures. Management compensates for the limitations of these non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management’s decision-making process.
You should not consider gross margin, operating margin, or Adjusted EBITDA in isolation or as a substitute for, or more meaningful than analysis of, our results as reported under GAAP. Gross margin, operating margin and Adjusted EBITDA may be defined differently by other companies in our industry. Our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
The following tables reconcile the non-GAAP financial measures of segment gross margin, operating margin and Adjusted EBITDA used by management to
Net loss attributable to the Partnership
, their most directly comparable GAAP measure, for the
three and six months ended
June 30, 2017
and
2016
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Reconciliation of Segment Gross Margin to Net loss attributable to the Partnership:
|
|
|
|
|
|
|
|
Gas Gathering and Processing Services segment gross margin
|
$
|
12,651
|
|
|
$
|
13,337
|
|
|
$
|
23,902
|
|
|
$
|
24,957
|
|
Liquid Pipelines and Services segment gross margin
|
6,683
|
|
|
9,432
|
|
|
13,152
|
|
|
15,284
|
|
Natural Gas Transportation Services segment gross margin
|
5,631
|
|
|
3,843
|
|
|
11,750
|
|
|
9,406
|
|
Offshore Pipelines and Services segment gross margin
|
25,623
|
|
|
20,558
|
|
|
51,426
|
|
|
33,819
|
|
Terminalling Services segment gross margin
(1)
|
10,760
|
|
|
11,586
|
|
|
21,920
|
|
|
21,030
|
|
Propane Marketing Services segment gross margin
|
17,952
|
|
|
22,316
|
|
|
37,254
|
|
|
50,621
|
|
Total Segment Gross Margin
|
79,300
|
|
|
81,072
|
|
|
159,404
|
|
|
155,117
|
|
Less:
|
|
|
|
|
|
|
|
Other direct operating expenses
(1)
|
28,886
|
|
|
29,579
|
|
|
55,902
|
|
|
57,545
|
|
Plus:
|
|
|
|
|
|
|
|
Gain (loss) on commodity derivatives, net
|
207
|
|
|
(1,367
|
)
|
|
(50
|
)
|
|
(1,605
|
)
|
Less:
|
|
|
|
|
|
|
|
Corporate expenses
|
30,084
|
|
|
22,281
|
|
|
62,928
|
|
|
43,382
|
|
Depreciation, amortization and accretion expense
|
30,170
|
|
|
26,398
|
|
|
59,521
|
|
|
51,439
|
|
(Gain) loss on sale of assets, net
|
52
|
|
|
478
|
|
|
(176
|
)
|
|
1,600
|
|
Interest expense
|
17,152
|
|
|
10,610
|
|
|
35,118
|
|
|
18,912
|
|
Other income
|
(72
|
)
|
|
(496
|
)
|
|
(86
|
)
|
|
(527
|
)
|
Other (income) expense, net
|
136
|
|
|
(365
|
)
|
|
806
|
|
|
(730
|
)
|
Income tax expense
|
801
|
|
|
701
|
|
|
1,924
|
|
|
1,436
|
|
Loss from discontinued operations, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
539
|
|
Net income attributable to noncontrolling interest
|
1,462
|
|
|
954
|
|
|
2,765
|
|
|
951
|
|
Net loss attributable to the Partnership
|
$
|
(29,164
|
)
|
|
$
|
(10,435
|
)
|
|
$
|
(59,348
|
)
|
|
$
|
(21,035
|
)
|
_______________________
(1)
Other direct operating expenses include Gas Gathering and Processing Services segment direct operating expenses of
$8.0 million
and
$8.9 million
for the three months ended June 30, 2017 and 2016, and
$16.1 million
and
17.5 million
, for the six months ended June 30, 2017 and 2016, respectively, Liquid Pipelines and Services segment direct operating expenses of
$1.8 million
and
$2.2 million
for the three months ended June 30, 2017 and 2016, and
$3.9 million
and
$4.7 million
for the six months ended June 30, 2017 and 2016, respectively, Natural Gas Transportation Services segment direct operating expenses of
$1.9 million
and
$2.0 million
for the three months ended June 30, 2017 and 2016, and
$3.2 million
and
$3.2 million
for the six months ended June 30, 2017 and 2016, respectively, Offshore Pipelines and Services segment direct operating expenses
of
$3.5 million
and
$2.8 million
for the three months ended June 30, 2017 and 2016, and
$6.1 million
and
$5.1 million
for the six months ended June 30, 2017 and 2016, respectively, and Propane Marketing Services segment direct operating expenses of
$13.6 million
and
$13.6 million
for the three months ended June 30, 2017 and 2016, and
$26.7 million
and
$27.1 million
for the six months ended June 30, 2017 and 2016, respectively. Direct operating expenses related to our Terminalling Services segment of
$3.0 million
and
$2.4 million
for the
three months ended June 30, 2017
and
2016
, respectively, as well as
$6.1 million
and
$5.0 million
for the
six months ended June 30, 2017
and 2016 are included within the calculation of Terminalling Services segment gross margin.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Reconciliation of Net loss attributable to the Partnership to Adjusted EBITDA:
|
|
|
|
|
|
|
|
Net loss attributable to the Partnership
|
$
|
(29,164
|
)
|
|
$
|
(10,435
|
)
|
|
$
|
(59,348
|
)
|
|
$
|
(21,035
|
)
|
Add:
|
|
|
|
|
|
|
|
Depreciation, amortization and accretion expense
|
29,885
|
|
|
26,398
|
|
|
58,956
|
|
|
51,439
|
|
Interest expense
|
13,900
|
|
|
9,800
|
|
|
28,835
|
|
|
17,400
|
|
Debt issuance costs paid
|
714
|
|
|
1,152
|
|
|
2,116
|
|
|
1,475
|
|
Unrealized loss on derivatives, net
|
1,748
|
|
|
3,488
|
|
|
3,021
|
|
|
4,870
|
|
Non-cash equity compensation expense
|
1,195
|
|
|
1,408
|
|
|
5,233
|
|
|
3,051
|
|
Transaction expenses
|
12,067
|
|
|
3,089
|
|
|
20,685
|
|
|
4,162
|
|
Income tax expense
|
801
|
|
|
701
|
|
|
1,924
|
|
|
1,436
|
|
Discontinued operations
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
168
|
|
Distributions from unconsolidated affiliates
|
15,900
|
|
|
26,562
|
|
|
38,394
|
|
|
40,077
|
|
General Partner contribution for cost reimbursement
|
15,130
|
|
|
3,500
|
|
|
24,744
|
|
|
5,000
|
|
Deduct:
|
|
|
|
|
|
|
|
Earnings in unconsolidated affiliates
|
17,552
|
|
|
11,702
|
|
|
32,954
|
|
|
19,045
|
|
Other income (loss)
|
126
|
|
|
(24
|
)
|
|
154
|
|
|
(47
|
)
|
OPEB plan net periodic benefit
|
10
|
|
|
(8
|
)
|
|
10
|
|
|
(8
|
)
|
Gain (loss) on sale of assets, net
|
(52
|
)
|
|
(478
|
)
|
|
176
|
|
|
(1,600
|
)
|
Adjusted EBITDA
|
$
|
44,540
|
|
|
$
|
54,463
|
|
|
$
|
91,266
|
|
|
$
|
90,653
|
|
General Trends and Outlook
We expect our business to continue to be affected by the key trends discussed in Part II, Item 7 of our Annual Report under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations — General Trends and Outlook.”
Results of Operations — Consolidated
Net loss attributable to the Partnership increased by
$18.7 million
for the
three months ended June 30, 2017
, and increased by
$38.2 million
, for the
six months ended June 30, 2017
as compared to the same periods in
2016
.
For the
three months ended June 30, 2017
, direct operating expenses
decreased
by
$0.1 million
primarily due to lower compressor rental costs. Corporate expenses
increased
by
$7.8 million
, or
35.0%
, due to an increase of $3.0 million of merger-related costs which include legal, consulting services and employee severance costs; $3.0 million relating to a settlement of litigation claim; $1.1 million transition expenses related to affiliate assets; $0.8 million of share of legal costs related to right-of-way agreements; and $0.3 million due to increased office expense, partially offset by capitalized labor of $1.1 million associated with our capital project to upgrade our accounting system and management fee income of $0.8 million. Interest expense
increased
by
$6.5 million
, or
61.7%
, as a result of additional borrowings to fund capital growth and acquisitions. Earnings from unconsolidated affiliates
increased
by
$5.9 million
, or
50.4%
, as result of our investments in the Emerald Transactions and the additional investments in Delta House occurring in Q2 and Q4 2016.
For the
six months ended June 30, 2017
, direct operating expenses
decreased
by
$0.6 million
primarily due to lower compressor rental costs. Corporate expenses
increased
by
$19.5 million
, or
45.1%
, due to an increase of $8.4 million of merger-related costs which include legal, consulting services and employee severance costs; $3.0 million relating to a settlement of litigation claim; $2.3 million of transition expenses related to affiliate assets; $1.5 million of labor costs mainly due to increased headcount and severance expense; $1.4 million of compensation relating to severance costs, $1.0 million of our share of legal costs related to right-of-way agreements; and higher contract labor costs and insurance premiums on offshore assets. Interest expense
increased
by
$16.2 million
, or
85.7%
, as a result of $14.0 million increase of interest expense and additional borrowings to fund capital growth and acquisitions. Earnings from unconsolidated affiliates
increased
by
$14.0 million
, or
73.7%
, as result of our investments in the Emerald Transactions and the additional investments in Delta House occurring in Q2 and Q4 2016.
Segment gross margin for the
three months ended June 30, 2017
was
$79.3 million
and
$159.4 million
for the
six months ended June 30, 2017
compared to
$81.1 million
for the
three months ended June 30, 2016
and
$155.1 million
for the
six months ended June 30, 2016
. This decrease of
$1.8 million
for the three months ended June 30, 2017 was primarily due to our Propane Marketing Services segment’s gross margin decrease of $
4.3 million
due to lower NGL sales as a result of lower oilfield services, expiration of short term marketing deals that expired in 2016 on crude oil supply logistics (“COSL”) for $2.7 million in our Liquid Pipelines and Services segment, partially offset by an increase in our Offshore Pipelines and Services segment of
$5.1 million
as a result of higher earnings in unconsolidated affiliates. For the
six months ended June 30, 2017
, the increase of
$4.3 million
was primarily due to higher segment gross margin in our Offshore Pipelines and Services segment of
$17.6 million
as a result of increased earnings in unconsolidated affiliates and the American Panther system that was acquired in Q2 2016, and an increase in our Natural Gas Transportation Services segment of $2.3 million mostly due to higher throughput as a result of new firm transportation contracts on our AlaTenn, MLGT, and Midla systems. These increases were partially offset by a decrease of
$13.3 million
related to our Propane Marketing Services segment primarily attributable to lower NGL sales as a result of the warmer winter temperatures and lower oilfield services.
For the
three months ended June 30, 2017
, Adjusted EBITDA decreased
$9.9 million
, or
18.2%
, compared to the same period in
2016
. The decrease is primarily related to lower distributions from our unconsolidated affiliates of
$10.7 million
and a larger net loss for the quarter. For the
six months ended June 30, 2017
, Adjusted EBITDA increased $
0.6
million, or
0.7%
, compared to the same period in
2016
. The increase is primarily related to support from our General Partner for cost reimbursement and partially offset by higher earnings from our unconsolidated affiliates.
We distributed
$21.4 million
to holders of our common units, or
$0.4125
per common unit, during the
three months ended June 30, 2017
, and
$46.3 million
, or
$0.8250
per common unit, during the
six months ended June 30, 2017
.
The results of operations by segment are discussed in further detail following this overview (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
Revenue:
|
|
|
|
|
|
|
|
Commodity sales
|
$
|
153,728
|
|
|
$
|
148,592
|
|
|
$
|
312,229
|
|
|
$
|
256,162
|
|
Services
|
39,698
|
|
|
38,611
|
|
|
81,086
|
|
|
74,655
|
|
Gain (loss) on commodity derivatives, net
|
207
|
|
|
(1,367
|
)
|
|
(50
|
)
|
|
(1,605
|
)
|
Total revenue
|
193,633
|
|
|
185,836
|
|
|
393,265
|
|
|
329,212
|
|
Operating expenses:
|
|
|
|
|
|
|
|
Costs of sales
|
128,816
|
|
|
115,080
|
|
|
261,601
|
|
|
189,018
|
|
Direct operating expenses
|
31,884
|
|
|
31,967
|
|
|
61,972
|
|
|
62,542
|
|
Corporate expenses
|
30,084
|
|
|
22,281
|
|
|
62,928
|
|
|
43,382
|
|
Depreciation, amortization and accretion
|
30,170
|
|
|
26,398
|
|
|
59,521
|
|
|
51,439
|
|
Total operating expenses
|
220,954
|
|
|
195,726
|
|
|
446,022
|
|
|
346,381
|
|
(Gain) loss on sale of assets, net
|
52
|
|
|
478
|
|
|
(176
|
)
|
|
1,600
|
|
Operating loss
|
(27,373
|
)
|
|
(10,368
|
)
|
|
(52,581
|
)
|
|
(18,769
|
)
|
Other income (expense), net
|
|
|
|
|
|
|
|
Interest expense
|
(17,152
|
)
|
|
(10,610
|
)
|
|
(35,118
|
)
|
|
(18,912
|
)
|
Other income
|
72
|
|
|
496
|
|
|
86
|
|
|
527
|
|
Earnings in unconsolidated affiliates
|
17,552
|
|
|
11,702
|
|
|
32,954
|
|
|
19,045
|
|
Loss from continuing operations before taxes
|
(26,901
|
)
|
|
(8,780
|
)
|
|
(54,659
|
)
|
|
(18,109
|
)
|
Income tax expense
|
(801
|
)
|
|
(701
|
)
|
|
(1,924
|
)
|
|
(1,436
|
)
|
Loss from continuing operations
|
(27,702
|
)
|
|
(9,481
|
)
|
|
(56,583
|
)
|
|
(19,545
|
)
|
Loss from discontinued operations, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
(539
|
)
|
Net loss
|
(27,702
|
)
|
|
(9,481
|
)
|
|
(56,583
|
)
|
|
(20,084
|
)
|
Less: Net income attributable to noncontrolling interests
|
1,462
|
|
|
954
|
|
|
2,765
|
|
|
951
|
|
Net loss attributable to the Partnership
|
$
|
(29,164
|
)
|
|
$
|
(10,435
|
)
|
|
$
|
(59,348
|
)
|
|
$
|
(21,035
|
)
|
Other Financial Data:
|
|
|
|
|
|
|
|
Gross margin
(1)
|
$
|
79,300
|
|
|
$
|
81,072
|
|
|
$
|
159,404
|
|
|
$
|
155,117
|
|
Adjusted EBITDA
(1)
|
$
|
44,540
|
|
|
$
|
54,463
|
|
|
$
|
91,266
|
|
|
$
|
90,653
|
|
_______________________
|
|
(1)
|
For definitions of gross margin and Adjusted EBITDA and reconciliations to their most directly comparable financial measure calculated and presented in accordance with GAAP, and a discussion of how we use gross margin and Adjusted EBITDA to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”
|
Three Months Ended
June 30, 2017
Compared to Three Months Ended
June 30, 2016
Total Revenue
. Our total revenue for the
three months ended June 30, 2017
was
$193.6 million
compared to
$185.8 million
for the
three months ended June 30, 2016
. This
increase
of
$7.8 million
was primarily due to the following:
|
|
•
|
an increase in our Gas Gathering and Processing segment revenue of
$9.3 million
primarily due to a new contract at our Longview plant for NGLs, natural gas and condensate for $11.9 million, partially offset by a decrease in natural gas and condensate volumes at Chatom/Bazor Ridge for $1.5 million due to lower system volumes, and due to a marketing contract that ended in Q4 of 2016 for $0.8 million;
|
|
|
•
|
a decrease in our Liquid Pipelines and Services segment revenue of
$1.6 million
mostly due to the expiration of short term marketing deals on COSL that expired in Q2 2016 of $12.6 million partially offset by $9.3 million of increased crude oil sales contracts;
|
|
|
•
|
an increase in our Natural Gas Transportation Services segment revenue of
$3.5 million
primarily due to an increase on the Magnolia system of $1.6 million due to favorable pricing and additional revenues on our MLGT and Midla system for $1.2 million due to new firm transportation contracts;
|
|
|
•
|
an increase in our Offshore Pipelines and Services segment revenue of
$1.5 million
due primarily to higher volumes and management fees from our acquired American Panther system for $1.0 million;
|
|
|
•
|
a
decrease
in our Terminalling Services segment revenue of
$1.7 million
mostly due to a decrease in sales of butane blending volumes due to timing of $2.6 million partially offset by a $0.7 million increase due to an expansion at our Harvey terminal; and
|
|
|
•
|
a decrease in our Propane Marketing Services segment revenue of
$2.7 million
due to a reduction of NGL revenues due to lower propane sales resulting from lower volumes driven by continued overall warmer than normal temperatures during the winter and a decline in oilfield services.
|
Cost of Sales
. Our purchases of natural gas, NGLs, condensate and crude for the
three months ended June 30, 2017
was
$128.8 million
compared to
$115.1 million
for the
three months ended June 30, 2016
. This
increase
of
$13.7 million
was mostly due to higher NGL, natural gas and condensate purchases of $9.2 million due to an increase in throughput at the Longview Plant, increase of $1.2 million due to additional throughput on the Gloria and Lafitte system and increased propane prices of $2.0 million compared to the same period last year.
Segment Gross Margin
. Segment gross margin for the
three months ended June 30, 2017
was
$79.3 million
compared to
$81.1 million
for the
three months ended June 30, 2016
. This decrease of
$1.8 million
was primarily due to our Propane Marketing Services segment of $4.4 million due to lower propane sales as a result of a decline in oilfield services, expiration of short term deals that expired in Q2 2016 on COSL for $2.7 million partially offset by our Offshore Pipelines and Services segment of
$5.1 million
as a result of increased earnings in unconsolidated affiliates and the American Panther system that was acquired in Q2 2016.
Direct Operating Expenses
. Direct operating expenses for the
three months ended June 30, 2017
were
$31.9 million
compared to
$32.0 million
for the
three months ended June 30, 2016
.
Corporate Expenses.
Corporate expenses for the
three months ended June 30, 2017
were
$30.1 million
compared to
$22.3 million
for the
three months ended June 30, 2016
. This increase of
$7.8 million
was primarily due to an increase of $3.0 million of merger related costs which include legal, consulting services and employee severance costs; $3.0 million relating to the settlement of a litigation claim; $1.1 million transition expenses related to affiliate assets; $0.8 million of share of legal costs related to right-of-way agreements; and $0.3 million related to higher office expense, which was partially offset by capitalized labor of $1.1 million and management fee income of $0.8 million.
Depreciation, Amortization and Accretion Expense
. Depreciation, amortization and accretion expense for the
three months ended June 30, 2017
was
$30.2 million
compared to
$26.4 million
for the
three months ended June 30, 2016
. This
increase
of
$3.8 million
was primarily due to the decrease in useful life of certain customer lists for $3.0 million and incremental depreciation of fixed assets acquired over the last 12 months.
Interest Expense
. Interest expense for the
three months ended June 30, 2017
was
$17.2 million
compared to
$10.6 million
for the
three months ended June 30, 2016
. The increase year over year of
$6.5 million
was primarily due to interest charges on the 8.5% and 3.77% Senior Notes which were issued in the second half of 2016, and increased borrowings on our revolving credit facility to
$678.0 million
. This increase was partially offset by the write-off of remaining deferred financing fees associated with the JPE revolver in March 2017 due to the JPE revolver being paid off, which resulted in a reduced interest expense of $1.2 million.
Earnings in Unconsolidated Affiliates.
Earnings in unconsolidated affiliates for the
three months ended June 30, 2017
was
$17.6 million
compared to
$11.7 million
for the
three months ended June 30, 2016
. This increase of $5.9 million was primarily due to incremental earnings of $4.2 million related to our investment in Delta House and $1.6 million related to Destin and Okeanos, Emerald Transactions.
Six months ended June 30, 2017
Compared to
Six months ended June 30, 2016
Total Revenue
. Our total revenue for the
six months ended June 30, 2017
was
$393.3 million
compared to
$329.2 million
for the
six months ended June 30, 2016
. This
increase
of
$64.1 million
was primarily due to the following:
|
|
•
|
an
increase
in our Gas Gathering and Processing segment revenue of
$20.5 million
primarily due to increased revenue from sales of NGLs and condensate at the Longview Plant of $25.7 million due to three new contracts, two of which started in Q1 2017. This was partially offset by a decrease due to marketing contracts that ended in Q4 of 2016 for $3.1 million and reduced NGL and condensate volumes at Chatom/Bazor Ridge for $1.1 million due to lower system volumes;
|
|
|
•
|
an
increase
in our Liquid Pipelines and Services segment revenue of
$34.4 million
due to an increase in revenue of $20.2 million due to more favorable pricing for COSL, an increase of $14.0 million due to additional crude oil sales contracts, and an increase of $1.2 million due to new wells coming on line on our Silver Dollar Pipeline;
|
|
|
•
|
an
increase
in our Natural Gas Transportation Services segment revenue of
$6.2 million
primarily due to an increase on the Magnolia system of $3.5 million due to favorable prices and additional revenues on our AlaTenn, MLGT, and Midla systems for $1.9 million due to new firm transportation contracts;
|
|
|
•
|
an
increase
in our Offshore Pipelines and Services segment revenue of
$9.3 million
due primarily to higher volumes and management fees from our acquired American Panther system for $6.7 million, and increased volumes sold to the Alliance Refinery on our Gloria system for $3.1 million;
|
|
|
•
|
an
increase
in our Terminalling Services segment revenue of
$2.7 million
mostly due to an expansion at our Harvey terminal for $2.1 million; and
|
|
|
•
|
a
decrease
in our Propane Marketing Services segment revenue of
$10.6 million
primarily due to a reduction in NGL revenues from lower propane sales driven by a decline in volumes associated with oilfield services and continued overall warmer than normal temperatures during winter.
|
Cost of Sales
. Our purchases of natural gas, NGLs, condensate and crude for the
six months ended June 30, 2017
was
$261.6 million
compared to
$189.0 million
for the
six months ended June 30, 2016
. This
increase
of
$72.6 million
was mostly due to higher NGL, natural gas and condensate purchases of $20.9 million due to an increase in throughput at the Longview Plant, increased crude oil prices and volumes in our Liquid Pipelines and Services segment driven by the favorable market conditions resulting in increased producer activity for $38.8 million and higher propane prices in our Propane Marketing Services segment for $4.4 million.
Segment Gross Margin
. Segment gross margin for the
six months ended June 30, 2017
was
$159.4 million
compared to
$155.1 million
for the
six months ended June 30, 2016
. This increase of
$4.3 million
was primarily due to higher segment gross margin in our Offshore Pipelines and Services segment of
$17.6 million
as a result of increased earnings in unconsolidated affiliates and the American Panther system that was acquired in Q2 2016 and due to an increase in our Natural Gas Transportation Services segment of
$2.4 million
mostly due to an increase in throughput as a result of new firm transportation contracts on our AlaTenn, MLGT, and Midla systems. These increases were partially offset by a decrease of
$13.3 million
related to our Propane Marketing Services segment primarily attributable to the warmer winter temperatures and lower oilfield services.
Direct Operating Expenses
. Direct operating expenses for the
six months ended June 30, 2017
were
$62.0 million
compared to
$62.5 million
for the
six months ended June 30, 2016
. This
decrease
of $0.5 million was primarily due to decreased compressor rental expense of $0.7 million and other expenses.
Corporate Expenses.
Corporate expenses for the
six months ended June 30, 2017
were
$62.9 million
compared to
$43.4 million
for the
six months ended June 30, 2016
. This increase of
$19.5 million
was primarily due to an increase of $8.4 million of merger related costs which include legal, consulting services and employee severance costs; $3.0 million relating to the settlement of a litigation claim; $2.3 million of transition expenses related to affiliate assets; $1.5 million of labor costs mainly due to increased headcount and severance expense; $1.4 million of compensation relating to severance costs; $1.0 million of share of legal costs related to right-of-way agreements; $0.8 million in contract labor costs; $0.6 million higher insurance premiums on offshore assets; which was partially offset by capitalized labor of $1.1 million.
Depreciation, Amortization and Accretion Expense
. Depreciation, amortization and accretion expense for the
six months ended June 30, 2017
was
$59.5 million
compared to
$51.4 million
for the
six months ended June 30, 2016
. This
increase
of
$8.1 million
was primarily due to the decrease in useful life for certain customer lists for $5.3 million and incremental depreciation of fixed assets acquired in the last 12 months mainly related to our Midla project.
Interest Expense
. Interest expense for the
six months ended June 30, 2017
was
$35.1 million
compared to
$18.9 million
for the
six months ended June 30, 2016
. This increase of
$16.2 million
was primarily due to interest on the 8.5% and 3.77% Senior Notes issued in the second half of 2016 increasing interest expense $14.0 million, increased borrowing on the Credit agreement $3.0 million and $1.3 million in associated financing costs, partially offset with the reduced interest expense of $1.2 million related to the acceleration of deferred financing costs due to the settlement of the JPE debt in March 2017.
Earnings in Unconsolidated Affiliates.
Earnings in unconsolidated affiliates for the
six months ended June 30, 2017
was
$33.0 million
compared to
$19.0 million
for the
six months ended June 30, 2016
. This increase of
$14.0 million
was primarily due to incremental earnings of $7.8 million related to our investment in Delta House and earnings of $5.3 million from the interests in the entities underlying the Emerald Transactions which were acquired in April 2016, offset by a decrease of $0.8 million from our interests in Main Pass Oil Gathering Company (“MPOG”).
Results of Operations — Segment Results
Gas Gathering and Processing Services Segment
The table below contains key segment performance indicators related to our Gathering and Processing Services segment (in thousands except operating and pricing data).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Segment Financial and Operating Data:
|
|
|
|
|
|
|
|
Gas Gathering and Processing Services segment
|
|
|
|
|
|
|
|
Financial data:
|
|
|
|
|
|
|
|
Commodity sales
|
$
|
33,650
|
|
|
$
|
24,274
|
|
|
$
|
62,423
|
|
|
$
|
41,277
|
|
Services
|
5,657
|
|
|
6,436
|
|
|
11,291
|
|
|
12,727
|
|
Revenue from operations
|
39,307
|
|
|
30,710
|
|
|
73,714
|
|
|
54,004
|
|
Loss on commodity derivatives, net
|
(98
|
)
|
|
(763
|
)
|
|
(105
|
)
|
|
(866
|
)
|
Segment revenue
|
39,209
|
|
|
29,947
|
|
|
73,609
|
|
|
53,138
|
|
Cost of sales
|
26,582
|
|
|
17,162
|
|
|
49,769
|
|
|
28,868
|
|
Direct operating expenses
|
8,045
|
|
|
8,945
|
|
|
16,110
|
|
|
17,492
|
|
Other financial data:
|
|
|
|
|
|
|
|
Segment gross margin
(2)
|
$
|
12,651
|
|
|
$
|
13,337
|
|
|
$
|
23,902
|
|
|
$
|
24,957
|
|
Operating data:
|
|
|
|
|
|
|
|
Average throughput (MMcf/d)
|
209.0
|
|
|
216.4
|
|
|
208.0
|
|
|
221.0
|
|
Average plant inlet volume (MMcf/d)
(1)
|
104.5
|
|
|
100.7
|
|
|
104.0
|
|
|
103.0
|
|
Average gross NGL production (Mgal/d)
(1)
|
398.8
|
|
|
263.3
|
|
|
348.0
|
|
|
269.0
|
|
Average gross condensate production (Mgal/d)
(1)
|
79.8
|
|
|
84.3
|
|
|
81.0
|
|
|
78.0
|
|
_______________________
(1)
Excludes volumes and gross production under our elective processing arrangements.
(2)
For the definition of segment gross margin and a discussion of how we use segment gross margin to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”
Three Months Ended
June 30, 2017
Compared to Three Months Ended
June 30, 2016
Commodity sales
. Commodity sales revenue for the
three months ended June 30, 2017
was
$33.7 million
compared to
$24.3 million
for the
three months ended June 30, 2016
. This increase of
$9.4 million
was primarily due to the following:
|
|
•
|
increased revenue from sales of NGLs, natural gas and condensate at the Longview Plant of $11.9 million due to three new contracts, two of which started in Q1 2017. One of the new contracts from Q1 2017 was previously a service contract;
|
|
|
•
|
partially offsetting this were marketing contracts that ended in Q4 of 2016 for $0.8 million; and
|
|
|
•
|
reduced NGL, natural gas and condensate volumes at Chatom/Bazor Ridge for $1.7 million due to lower system volumes;
|
Services
. Segment services revenue for the period ended
June 30, 2017
was
$5.7 million
compared to
$6.4 million
for the
three months ended June 30, 2016
. The decrease is primarily due to a new contract that increased commodity sales but led to a decline in transportation and fractionation fees of $0.6 million on Longview and lower compression and gathering charges of $0.5 million on our Lavaca system.
Cost of Sales
. Purchases of natural gas, NGLs and condensate for the
three months ended June 30, 2017
were
$26.6 million
compared to
$17.2 million
for the
three months ended June 30, 2016
. This increase of
$9.4 million
was primarily due to the increase
of NGL, natural gas and condensate sales at the Longview Plant, as mentioned above. Additionally, there was also an increase in throughput on our rail and increased freight charges due to new contracts.
Segment Gross Margin.
Segment gross margin for the
three months ended June 30, 2017
was
$12.7 million
compared to
$13.3 million
for the
three months ended June 30, 2016
for reasons discussed above.
Direct Operating Expenses.
Direct operating expenses of
$8.0 million
for
three months ended June 30, 2017
declined from
$8.9 million
for the
three months ended June 30, 2016
, mainly due to our ongoing cost savings initiatives reducing labor costs $0.5 million, $0.2 million of lower regulatory costs, $0.1 million due to the timing of chemical purchases and costs related to measurement equipment, partially offset by increased contract services costs of $0.2 million.
Six months ended June 30, 2017
Compared to
Six months ended June 30, 2016
Commodity sales
. Commodity sales revenue for the
six months ended June 30, 2017
was
$62.4 million
compared to
$41.3 million
for the
six months ended June 30, 2016
. This increase of $21.1 million was primarily due to the following:
|
|
•
|
increased revenue from sales of NGLs and condensate at the Longview Plant of $25.7 million due to three new contracts, two of which started in Q1 2017. One of the new contracts from Q1 2017 had previously been a service contract;
|
|
|
•
|
partially offsetting this was a decrease due to marketing contracts that ended in Q4 of 2016 for $3.1 million; and
|
|
|
•
|
reduced NGL and condensate volumes at Chatom/Bazor Ridge for $2.1 million due to lower system volumes.
|
Services
. Segment services revenue for the six months ended
June 30, 2017
was
$11.3 million
compared to
$12.7 million
for the
six months ended June 30, 2016
. The decrease is primarily due to decline in compression and gathering charges by $1.5 million on our Lavaca system.
Cost of Sales
. Purchases of natural gas, NGLs and condensate for the
six months ended June 30, 2017
were
$49.8 million
compared to
$28.9 million
for the
six months ended June 30, 2016
. This
increase
of
$20.9 million
was primarily due to the increase of NGL, natural gas and condensate sales at the Longview Plant, as mentioned above. Additionally, there was also an decrease in throughput on our rail and increased freight charges due to new contracts.
Segment Gross Margin.
Segment gross margin for the
six months ended June 30, 2017
was
$23.9 million
compared to
$25.0 million
for the
six months ended June 30, 2016
as discussed above.
Direct Operating Expenses.
Direct operating expenses of
$16.1 million
for
six months ended June 30, 2017
declined from
$17.5 million
for the
six months ended June 30, 2016
, mainly due to our ongoing cost savings initiatives reducing compressor rentals and labor costs by $0.7 million and $0.6 million, respectively. Additionally we had $0.2 million lower regulatory costs, partially offset by higher contract services of $0.4 million.
Liquid Pipelines and Services Segment
The table below contains key segment performance indicators related to our Liquid Pipelines and Services segment (in thousands except operating and pricing data).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Segment Financial and Operating Data:
|
|
|
|
|
|
|
|
Liquid Pipelines and Services segment
|
|
|
|
|
|
|
|
Financial data:
|
|
|
|
|
|
|
|
Commodity sales
|
$
|
79,566
|
|
|
$
|
82,257
|
|
|
$
|
158,511
|
|
|
$
|
123,177
|
|
Services
|
2,737
|
|
|
3,158
|
|
|
5,831
|
|
|
6,753
|
|
Revenue from operations
|
82,303
|
|
|
85,415
|
|
|
164,342
|
|
|
129,930
|
|
Gain (loss) on commodity derivatives, net
|
297
|
|
|
(716
|
)
|
|
669
|
|
|
(948
|
)
|
Earnings in unconsolidated affiliates
|
1,482
|
|
|
1,009
|
|
|
2,569
|
|
|
1,009
|
|
Segment revenue
|
84,082
|
|
|
85,708
|
|
|
167,580
|
|
|
129,991
|
|
Cost of sales
|
77,332
|
|
|
76,992
|
|
|
154,409
|
|
|
115,645
|
|
Direct operating expenses
|
1,833
|
|
|
2,235
|
|
|
3,906
|
|
|
4,701
|
|
Other financial data:
|
|
|
|
|
|
|
|
Segment gross margin
(1)
|
$
|
6,683
|
|
|
$
|
9,432
|
|
|
$
|
13,152
|
|
|
$
|
15,284
|
|
Operating data:
|
|
|
|
|
|
|
|
Average throughput Pipeline (Bbls/d)
|
32,957
|
|
|
31,090
|
|
|
33,020
|
|
|
31,418
|
|
Average throughput Truck (Bbls/d)
|
1,943
|
|
|
2,016
|
|
|
1,751
|
|
|
1,619
|
|
_______________________
(1)
For the definition of segment gross margin and a discussion of how we use segment gross margin to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”
Three Months Ended
June 30, 2017
Compared to Three Months Ended
June 30, 2016
Commodity Sales.
Segment revenue from crude oil for the
three months ended June 30, 2017
was
$79.6 million
compared to
$82.3 million
for the
three months ended June 30, 2016
. The decrease of
$2.7 million
was primarily due to the expiration of short term marketing deals on COSL that expired in Q2 2016 for $12.6 million partially offset by $9.3 million of increased marketing crude oil contracts.
Services revenue.
Segment services revenue for the
three months ended June 30, 2017
was
$2.7 million
compared to
$3.2 million
for the
three months ended June 30, 2016
. The decrease of $0.5 million was primarily due to a decline in crude oil transportation revenue due to lower volumes and price as well as declining trucking rates as a result of increased competition.
Earnings in Unconsolidated Affiliates.
Earnings in unconsolidated affiliates for the
three months ended June 30, 2017
was
$1.5 million
compared to
$1.0 million
for the
three months ended June 30, 2016
. The increase of $0.5 million was due to the additional month of earnings in second quarter 2017 versus 2016 as the interests in Tri-states and Wilprise were acquired in late April 2016.
Cost of Sales
.
Purchases of crude oil for the
three months ended June 30, 2017
was
$77.3 million
compared to
$77.0 million
for the
three months ended June 30, 2016
and remained relatively flat.
Segment Gross Margin
. Segment gross margin for the
three months ended June 30, 2017
, was
$6.7 million
compared to
$9.4 million
for the
three months ended June 30, 2016
. Segment margin decreased by
$2.7 million
due to the reasons discussed above.
Direct Operating Expenses
. Direct operating expenses of
$1.8 million
for the
three months ended June 30, 2017
declined from
$2.2 million
for the
three months ended June 30, 2016
mainly due to a decrease of $0.3 million for equipment lease and measurement costs and $0.1 million lower property tax expense .
Six months ended June 30, 2017
Compared to
Six months ended June 30, 2016
Commodity Sales.
Segment revenue from crude oil for the
six months ended June 30, 2017
was
$158.5 million
compared to
$123.2 million
for the
six months ended June 30, 2016
. The increase of $35.3 million was primarily due to an increase in revenue of $20.4 million due to favorable pricing for COSL, an increase of $14.0 million due to additional crude oil sales contracts, and an increase of $1.1 million due to new wells coming on line, on our Silver Dollar Pipeline.
Services revenue.
Segment services revenue for the
six months ended June 30, 2017
was
$5.8 million
compared to
$6.8 million
for the
six months ended June 30, 2016
. The decrease of $1.0 million was primarily due to tariff rate reductions of $0.6 million and the roll off in first quarter of Bakken system management fees.
Earnings in Unconsolidated Affiliates.
Earnings in unconsolidated affiliates for the
six months ended June 30, 2017
was
$2.6 million
compared to
$1.0 million
for the
six months ended June 30, 2016
, resulting from the acquisition of Tri-states and Wilprise in late April 2016.
Cost of Sales
.
Purchases of crude oil for the
six months ended June 30, 2017
was
$154.4 million
compared to
$115.6 million
for the
six months ended June 30, 2016
. The
increase
of
$38.8 million
is primarily due to the increase in crude prices and crude sales volumes driven by favorable market conditions resulting in higher realized crude prices and increased producer activity of $24.2 million for COSL. Additionally, there was an increase of $13.3 million due to an additional crude oil sales contract added in Q1 2017.
Segment Gross Margin
. Segment gross margin for the
six months ended June 30, 2017
, was
$13.2 million
compared to
$15.3 million
for the
six months ended June 30, 2016
. Segment margin
decreased
by
$2.1 million
due to the reasons discussed above.
Direct Operating Expenses
. Direct operating expenses of
$3.9 million
for the
six months ended June 30, 2017
declined from
$4.7 million
for the
six months ended June 30, 2016
mainly due to $0.3 million of lower property tax expense, $0.2 million equipment lease costs and $0.2 million for measurement equipment costs.
Natural Gas Transportation Services Segment
The table below contains key segment performance indicators related to our Natural Gas Transportation Services segment
(in thousands except operating and pricing data).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Segment Financial and Operating Data:
|
|
|
|
|
|
|
|
Natural Gas Transportation Services segment
|
|
|
|
|
|
|
|
Financial data:
|
|
|
|
|
|
|
|
Commodity sales
|
$
|
6,442
|
|
|
$
|
4,226
|
|
|
$
|
13,310
|
|
|
$
|
8,875
|
|
Services
|
4,955
|
|
|
3,651
|
|
|
10,525
|
|
|
8,797
|
|
Segment revenue
|
11,397
|
|
|
7,877
|
|
|
23,835
|
|
|
17,672
|
|
Cost of sales
|
5,678
|
|
|
4,026
|
|
|
11,938
|
|
|
8,250
|
|
Direct operating expenses
|
1,928
|
|
|
1,963
|
|
|
3,163
|
|
|
3,190
|
|
Other financial data:
|
|
|
|
|
|
|
|
Segment gross margin
(1)
|
$
|
5,631
|
|
|
$
|
3,843
|
|
|
$
|
11,750
|
|
|
$
|
9,406
|
|
Operating data:
|
|
|
|
|
|
|
|
Average throughput (MMcf/d)
|
407.0
|
|
|
388.0
|
|
|
398.0
|
|
|
433.0
|
|
_______________________
(1)
For the definition of segment gross margin and a discussion of how we use segment gross margin to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”
Three Months Ended
June 30, 2017
Compared to Three Months Ended
June 30, 2016
Commodity Sales
. Segment sales of natural gas, NGLs and condensate for the
three months ended June 30, 2017
were
$6.4 million
compared to
$4.2 million
for the
three months ended June 30, 2016
. The increase of $2.2 million is primarily due to an increase on the Magnolia system of $1.6 million as a result of favorable prices in Q2 2017 and marketing increases for $0.4 million.
Services revenue.
Segment services revenue for the
three months ended June 30, 2017
was
$5.0 million
compared to
$3.7 million
for the
three months ended June 30, 2016
. This increase of $1.3 million was mostly due to new firm transportation contracts on our MLGT system.
Cost of Sales
. Purchases of natural gas, NGLs and condensate for the
three months ended June 30, 2017
were
$5.7 million
as compared to
$4.0 million
for the
three months ended June 30, 2016
. This increase is primarily due to higher volumes and prices on Magnolia for $1.6 million.
Segment Gross Margin
. Segment gross margin for the
three months ended June 30, 2017
, was
$5.6 million
compared to
$3.8 million
for the
three months ended June 30, 2016
. This increase of $1.8 million was primarily due to reasons discussed above.
Direct Operating Expenses
. Direct operating expenses remained flat at
$1.9 million
for the
three months ended June 30, 2017
and 2016.
Six months ended June 30, 2017
Compared to
Six months ended June 30, 2016
Commodity Sales
. Segment sales of natural gas, NGLs and condensate for the
six months ended June 30, 2017
were
$13.3 million
compared to
$8.9 million
for the
six months ended June 30, 2016
. The increase of $4.4 million is primarily due to an increase on the Magnolia system of $3.5 million as a result of favorable prices in 2017 and marketing increases for $1.0 million.
Services revenue.
Segment services revenue for the
six months ended June 30, 2017
was
$10.5 million
compared to
$8.8 million
for the
six months ended June 30, 2016
. This increase of $1.7 million was mostly due to new firm transportation contracts on our AlaTenn and MLGT systems.
Cost of Sales
. Purchases of natural gas, NGLs and condensate for the
six months ended June 30, 2017
were
$11.9 million
as compared to
$8.3 million
for the
six months ended June 30, 2016
This increase is primarily due to higher prices on Magnolia for $3.2 million and marketing activity of $0.6 million.
Segment Gross Margin
. Segment gross margin for the
six months ended June 30, 2017
, was
$11.8 million
compared to
$9.4 million
for the
six months ended June 30, 2016
. This
increase
of
$2.4 million
was primarily due to reasons discussed above.
Direct Operating Expenses
. Direct operating expenses remained flat at
$3.2 million
for the
six months ended June 30,
2017 and 2016.
Offshore Pipelines and Services Segment
The table below contains key segment performance indicators related to our Offshore Pipelines and Services segment (in thousands except operating and pricing data).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Segment Financial and Operating Data:
|
|
|
|
|
|
|
|
Offshore Pipelines and Services segment
|
|
|
|
|
|
|
|
Financial data:
|
|
|
|
|
|
|
|
Commodity sales
|
$
|
2,440
|
|
|
$
|
1,815
|
|
|
$
|
6,203
|
|
|
$
|
3,820
|
|
Services
|
9,699
|
|
|
8,830
|
|
|
20,767
|
|
|
13,825
|
|
Revenue from operations
|
12,139
|
|
|
10,645
|
|
|
26,970
|
|
|
17,645
|
|
Earnings in unconsolidated affiliates
|
16,070
|
|
|
10,693
|
|
|
30,385
|
|
|
18,036
|
|
Segment revenue
|
28,209
|
|
|
21,338
|
|
|
57,355
|
|
|
35,681
|
|
Cost of sales
|
2,586
|
|
|
778
|
|
|
5,929
|
|
|
1,860
|
|
Direct operating expenses
|
3,490
|
|
|
2,802
|
|
|
6,070
|
|
|
5,055
|
|
Other financial data:
|
|
|
|
|
|
|
|
Segment gross margin
(1)
|
$
|
25,623
|
|
|
$
|
20,558
|
|
|
$
|
51,426
|
|
|
$
|
33,819
|
|
Operating data:
|
|
|
|
|
|
|
|
Average throughput (MMcf/d)
|
322.0
|
|
|
493.0
|
|
|
363.0
|
|
|
462.0
|
|
_______________________
(1)
For the definition of segment gross margin and a discussion of how we use segment gross margin to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”
(2) These volumes exclude Equity Investment volumes.
Three Months Ended
June 30, 2017
Compared to Three Months Ended
June 30, 2016
Commodity Sales
. Segment sales of natural gas, NGLs and condensate for the
three months ended June 30, 2017
was
$2.4 million
compared to
$1.8 million
for the
three months ended June 30, 2016
. This increase of $0.6
million was primarily due to increased volumes sold to the Alliance Refinery on our Gloria system.
Services revenue
. Segment services revenue for the
three months ended June 30, 2017
was
$9.7 million
compared to
$8.8 million
for the
three months ended June 30, 2016
. This increase of $0.9 million was mostly due to higher management fees and volumes related to the addition of American Panther.
Earnings in unconsolidated affiliates
.
Earnings for the
three months ended June 30, 2017
were
$16.1 million
compared to
$10.7 million
for the
three months ended June 30, 2016
. The increase was due to the additional Delta House acquisitions in Q2 and Q4 2016, which is continuing to perform near nameplate capacity as a result of strong performance by the producers that supply volumes to the offshore facility.
Cost of Sales
. Purchases of natural gas, NGLs and condensate for the
three months ended June 30, 2017
were
$2.6 million
compared to
$0.8 million
for the
three months ended June 30, 2016
. This increase of $1.8 million was mainly due to additional throughput on our Gloria system for $1.0 million and $0.2 million attributable to additional throughput on the Lafitte system.
Segment Gross Margin
. Segment gross margin for the
three months ended June 30, 2017
was
$25.6 million
compared to
$20.6 million
for the
three months ended June 30, 2016
. This increase of
$5.0 million
was primarily due to earnings in unconsolidated affiliates and from our American Panther system as noted above.
Direct Operating Expenses
. Direct operating expenses were
$3.5 million
and
$2.8 million
on the
three months ended June 30, 2017
and 2016, respectively . The increase of $0.7 million is mainly due to the addition of a Gulf of Mexico pipeline acquired in April 2016.
Six months ended June 30, 2017
Compared to
Six months ended June 30, 2016
Commodity Sales
. Segment sales of natural gas, NGLs and condensate for the
six months ended June 30, 2017
was
$6.2 million
compared to
$3.8 million
for the
six months ended June 30, 2016
. This increase of $2.4
million was primarily due to increased
volumes sold to the Alliance Refinery on our Gloria system for $3.1 million partially offset by $1.0 million decrease on our HPGG system due to platform maintenance.
Services revenue
.
Segment services revenue for the
six months ended June 30, 2017
was
$20.8 million
compared to
$13.8 million
for the
six months ended June 30, 2016
. This increase of $7.0 million was mostly due to higher management fees of $4.3 million and $2.4 million for our crude transportation volumes related to the acquisition of American Panther in April 2016.
Earnings in unconsolidated affiliates
.
Earnings for the
six months ended June 30, 2017
were
$30.4 million
compared to
$18.0 million
for the
six months ended June 30, 2016
. The increase was due to the additional Delta House acquisitions in Q2 and Q4 2016, which is continuing to perform near nameplate capacity as a result of strong performance by the producers that supply volumes to the offshore facility.
Cost of Sales
. Purchases of natural gas, NGLs and condensate for the
six months ended June 30, 2017
were
$5.9 million
compared to
$1.9 million
for the
six months ended June 30, 2016
. This
increase
of
$4.0 million
was mainly due to additional throughput on our Gloria system.
Segment Gross Margin
. Segment gross margin for the
six months ended June 30, 2017
was
$51.4 million
compared to
$33.8 million
for the
six months ended June 30, 2016
. This
increase
of
$17.6 million
was primarily due to earnings in unconsolidated affiliates and from our American Panther system as noted above.
Direct Operating Expenses
. Direct operating expenses of
$6.1 million
and
$5.1 million
for the
six months ended June 30, 2017
and 2016. This increase of $1.0 million is mainly due to the addition of Gulf of Mexico pipeline acquired in April 2016.
Terminalling Services Segment
The table below contains key segment performance indicators related to our Terminalling Services segment (in thousands except operating data).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Segment Financial and Operating Data:
|
|
|
|
|
|
|
|
Terminalling Services segment
|
|
|
|
|
|
|
|
Financial data:
|
|
|
|
|
|
|
|
Commodity sales
|
$
|
2,378
|
|
|
$
|
5,037
|
|
|
$
|
7,550
|
|
|
$
|
7,739
|
|
Services
|
13,453
|
|
|
12,778
|
|
|
26,907
|
|
|
24,471
|
|
Revenue from operations
|
15,831
|
|
|
17,815
|
|
|
34,457
|
|
|
32,210
|
|
Loss on commodity derivatives, net
|
—
|
|
|
(260
|
)
|
|
—
|
|
|
(436
|
)
|
Segment revenue
|
15,831
|
|
|
17,555
|
|
|
34,457
|
|
|
31,774
|
|
Cost of sales
|
2,073
|
|
|
3,542
|
|
|
6,466
|
|
|
5,747
|
|
Direct operating expenses
|
2,998
|
|
|
2,388
|
|
|
6,071
|
|
|
4,997
|
|
Other financial data:
|
|
|
|
|
|
|
|
Segment gross margin
(2)
|
$
|
10,760
|
|
|
$
|
11,586
|
|
|
$
|
21,920
|
|
|
$
|
21,030
|
|
Operating data:
|
|
|
|
|
|
|
|
Contracted capacity (Bbls)
|
5,139,367
|
|
5,018,233
|
|
5,219,517
|
|
4,768,767
|
Design capacity (Bbls)
(3)
|
5,400,800
|
|
5,150,800
|
|
5,400,800
|
|
4,975,800
|
Storage utilization
(1)
|
95.2
|
%
|
|
97.4
|
%
|
|
96.6
|
%
|
|
95.8
|
%
|
Terminalling and Storage throughput (Bbls/d)
|
60,711
|
|
|
59,306
|
|
|
116,990
|
|
|
118,597
|
|
_______________________
(1)
Excludes storage utilization associated with our discontinued operations.
(2)
For the definition of segment gross margin and a discussion of how we use segment gross margin to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”
(3)
Excludes Caddo Mills and North Little Rock.
Three Months Ended
June 30, 2017
Compared to Three Months Ended
June 30, 2016
Commodity Sales.
Segment commodity sales for the
three months ended June 30, 2017
was
$2.4 million
compared to
$5.0 million
for the
three months ended June 30, 2016
. The decrease of $2.6 million relates to our refined products and is driven by the timing of our sale of butane blending volumes.
Services Revenue
. Segment services revenue for the
three months ended June 30, 2017
was
$13.5 million
compared to
$12.8 million
for the
three months ended June 30, 2016
. This increase is primarily driven by the increase in contracted capacity as a result of the expansion efforts at the Harvey terminal which started in 2015.
Cost of Sales
. Segment purchases of NGLs for the
three months ended June 30, 2017
was
$2.1 million
compared to
$3.5 million
for the
three months ended June 30, 2016
. The decrease of $1.4 million is due to the decrease in sales of our butane blending volumes.
Segment Gross Margin
. Segment gross margin for the
three months ended June 30, 2017
was
$10.8 million
compared to
$11.6 million
for the
three months ended June 30, 2016
. The
$0.8 million
decrease in segment gross margin is mostly driven by the decrease in sale of butane blending volumes as noted above.
Direct Operating Expenses
. Segment direct operating expense for the
three months ended June 30, 2017
was
$3.0 million
compared to
$2.4 million
for the
three months ended June 30, 2016
. This increase was mainly driven by higher operating costs related to our Harvey expansion.
Six months ended June 30, 2017
Compared to
Six months ended June 30, 2016
Commodity Sales.
Segment commodity sales for the
six months ended June 30, 2017
was
$7.5 million
compared to
$7.7 million
for the
six months ended June 30, 2016
. The small decrease of $0.2 million relates to our refined products and is driven by a decrease in butane blending volumes.
Services Revenue
. Segment services revenue for the
six months ended June 30, 2017
was
$26.9 million
compared to
$24.5 million
for the
six months ended June 30, 2016
. The $2.4 million increase is primarily driven by a $2.1 million increase in contracted capacity and related ancillary services as a result of the expansion efforts at the Harvey terminal.
Cost of Sales
. Segment purchases of NGLs for the
six months ended June 30, 2017
was
$6.5 million
compared to
$5.7 million
for the
six months ended June 30, 2016
. The
increase
of
$0.8 million
is primarily due to the higher butane costs related to volumes sold.
Segment Gross Margin
. Segment gross margin for the
six months ended June 30, 2017
was
$21.9 million
compared to
$21.0 million
for the
six months ended June 30, 2016
. The
$0.9 million
increase
in segment gross margin is mostly driven by the Harvey storage expansion as noted above.
Direct Operating Expenses
. Segment direct operating expense for the
six months ended June 30, 2017
was
$6.1 million
compared to
$5.0 million
for the
six months ended June 30, 2016
. This increase was mainly driven by higher operating costs related to our Harvey expansion.
Propane Marketing Services Segment
The table below contains key segment performance indicators related to our Propane Marketing Services segment (in thousands except operating data).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Segment Financial and Operating Data:
|
|
|
|
|
|
|
|
Propane Marketing Services segment
|
|
|
|
|
|
|
|
Financial data:
|
|
|
|
|
|
|
|
Commodity sales
|
$
|
29,252
|
|
|
$
|
30,984
|
|
|
$
|
64,232
|
|
|
$
|
71,274
|
|
Services
|
3,197
|
|
|
3,757
|
|
|
5,765
|
|
|
8,082
|
|
Revenue from operations
|
32,449
|
|
|
34,741
|
|
|
69,997
|
|
|
79,356
|
|
Gain (loss) on commodity derivatives, net
|
8
|
|
|
374
|
|
|
(614
|
)
|
|
647
|
|
Segment revenue
|
32,457
|
|
|
35,115
|
|
|
69,383
|
|
|
80,003
|
|
Cost of sales
|
14,565
|
|
|
12,580
|
|
|
33,090
|
|
|
28,648
|
|
Direct operating expenses
|
13,590
|
|
|
13,634
|
|
|
26,652
|
|
|
27,107
|
|
Other financial data:
|
|
|
|
|
|
|
|
Segment gross margin
(1)
|
$
|
17,952
|
|
|
$
|
22,316
|
|
|
$
|
37,254
|
|
|
$
|
50,621
|
|
Operating data:
|
|
|
|
|
|
|
|
NGL and refined product sales (Mgal/d)
|
151.6
|
|
164.3
|
|
176.7
|
|
201.7
|
_______________________
(1)
For the definition of segment gross margin and a discussion of how we use segment gross margin to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”
Three Months Ended
June 30, 2017
Compared to Three Months Ended
June 30, 2016
Commodity Sales.
Segment sales of NGLs for the
three months ended June 30, 2017
were
$29.3 million
compared to
$31.0 million
for the
three months ended June 30, 2016
. This decrease of $1.7 million was due to a reduction of NGL revenues due to lower NGL sales resulting from lower volumes driven by continued overall warmer than normal temperatures and a decline in oilfield services.
Services Revenue.
Services revenue for the
three months ended June 30, 2017
was
$3.2 million
compared to
$3.8 million
for the
three months ended June 30, 2016
. This decrease of $0.6 million was due to the same business drivers as described in the “Commodity Sales” section above.
Cost of Sales
. Segment purchases of NGLs for the
three months ended June 30, 2017
was
$14.6 million
compared to
$12.6 million
for the
three months ended June 30, 2016
. The increase is due to higher propane prices in the
three months ended June 30, 2017
compared to the same period in the prior year partially offset by lower sales volumes.
Segment Gross Margin
. Segment gross margin for the
three months ended June 30, 2017
was
$18.0 million
compared to
$22.3 million
for the
three months ended June 30, 2016
. The decrease of
$4.3 million
is driven by the reduced sales revenue and higher propane prices.
Direct Operating Expenses
. Segment direct operating expenses for the
three months ended June 30, 2017
was
$13.6 million
comparable to
$13.6 million
for the
three months ended June 30, 2016
.
Six months ended June 30, 2017
Compared to
Six months ended June 30, 2016
Commodity Sales.
Segment sales of NGLs for the
six months ended June 30, 2017
were
$64.2 million
compared to
$71.3 million
for the
six months ended June 30, 2016
. This decrease of $7.1 million was due to a reduction of NGL revenues due to lower NGL sales driven by a decline in volumes associated with oilfield services and continued overall warmer than normal temperatures during winter.
Services Revenue.
Services revenue for the
six months ended June 30, 2017
was
$5.8 million
compared to
$8.1 million
for the
six months ended June 30, 2016
. This decrease of $2.3 million was due to the same business drivers as described in the ‘Commodity Sales’ section above.
Cost of Sales
. Segment purchases of NGLs for the
six months ended June 30, 2017
was
$33.1 million
compared to
$28.6 million
for the
six months ended June 30, 2016
. The increase is due to higher propane prices in the
six months ended June 30, 2017
compared to the same period in the prior year offset by lower sales volumes.
Segment Gross Margin
. Segment gross margin for the
six months ended June 30, 2017
was
$37.3 million
compared to
$50.6 million
for the
six months ended June 30, 2016
. The
decrease
of
$13.3 million
is driven by the reduced sales revenue and higher propane prices.
Direct Operating Expenses
. Segment direct operating expenses for the
six months ended June 30, 2017
was
$26.7 million
compared to
$27.1 million
for the
six months ended June 30, 2016
. The decrease is driven by lower distribution costs as a result of lower volumes as well as improved fleet efficiencies.
Liquidity and Capital Resources
Our business is capital intensive and requires significant investment for the maintenance of existing assets and the acquisition and development of new systems and facilities.
Our principal sources of liquidity include cash from operating activities, borrowings under our Credit Agreement (as defined herein), or through private transactions. In addition, we may seek to raise capital through the issuance of secured and unsecured senior notes. Given our historical success in accessing various sources of liquidity, we believe that the sources of liquidity described above will be sufficient to meet our short-term working capital requirements, medium-term maintenance capital expenditure requirements, and quarterly cash distributions for at least the next four quarters. In the event these sources are not sufficient, we would pursue other sources of cash funding, including, but not limited to, additional forms of debt or equity financing. In addition, we would reduce non-essential capital expenditures, direct operating expenses and corporate expenses, as necessary, and our Partnership Agreement allows us to reduce or eliminate quarterly distributions, if required to maintain ongoing operations. We plan to finance our growth capex mainly through additional forms of debt or equity financing, as well as sale of non-core assets.
Changes in natural gas, crude oil, NGL and condensate prices and the terms of our contracts may have a direct impact on our generation and use of cash from operations due to their impact on net income (loss), along with the resulting changes in working capital. In the past, we mitigated a portion of our anticipated commodity price risk associated with the volumes from our gathering and processing activities with fixed price commodity swaps. For additional information regarding our derivative activities, see the information provided under Part II, Item 7A of our Annual Report under the caption, “Quantitative and Qualitative Disclosures about Market Risk” and Part I, Item 3 of this Quarterly Report under the caption “Quantitative and Qualitative Disclosures about Market Risk”.
The counterparties to certain of our commodity swap contracts are investment-grade rated financial institutions. Under these contracts, we may be required to provide collateral to the counterparties in the event that our potential payment exposure exceeds a predetermined collateral threshold. Collateral thresholds are set by us and each counterparty, as applicable, in the master contract that governs our financial transactions based on our and the counterparty’s assessment of creditworthiness. The assessment of our position with respect to the collateral thresholds is determined on a counterparty by counterparty basis, and is impacted by the representative forward price curves and notional quantities under our swap contracts. Due to the interrelation between the representative natural gas and crude oil forward price curves, it is not practical to determine a single pricing point at which our swap contracts will meet the collateral thresholds as we may transact multiple commodities with the same counterparty. Depending on daily commodity prices, the amount of collateral posted can go up or down on a daily basis. As of
June 30, 2017
, we have not been required to post collateral with our counterparties.
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. For the quarter ended
June 30, 2017
, we did not sell any common units under our ATM program and have approximately $96.8 million remaining available for sale under the Partnership’s ATM Equity Offering Sales Agreement.
Our Revolving Credit Facility
On March 8, 2017, we entered into the Second Amended and Restated Credit Agreement, with Bank of America N.A., as Administrative Agent, Collateral Agent and L/C Issuer, Wells Fargo Bank, National Association, as Syndication Agent, and other lenders or Credit Agreement, which increased our borrowing capacity from $750.0 million to $900.0 million and provided for an accordion feature that will permit, subject to customary conditions, the borrowing capacity under the facility to be increased to a
maximum of $1.1 billion. The $900 million in lending commitments under the Credit Agreement includes a $30 million sublimit for borrowings by the Blackwater Borrower and a $100 million sublimit for standby letters of credit, which was increased in the Credit Agreement from $50 million. 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 and the guarantees of those obligations are secured, subject to certain exceptions
by a first-priority lien on and security interest in substantially all of our assets and the assets of all, subject to certain exceptions, existing and future subsidiaries and all of the capital stock of our existing and future subsidiaries. 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 Note Purchase Agreement (as defined below), we 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.
For the
six months ended June 30,
2017
and
2016
, the weighted average interest rate on borrowings under our Credit Agreement and the JPE Revolver (as defined below) was approximately
4.67%
and
4.15%
, respectively. At
June 30, 2017
and
December 31, 2016
, letters of credit outstanding under the Credit Agreement were
$32.3 million
and
$7.4 million
, respectively. As of
June 30, 2017
, we had approximately
$678.0 million
of borrowings and
$32.3 million
of letters of credit outstanding under the Credit Agreement resulting in
$189.6 million
of available borrowing capacity.
As of
June 30, 2017
, our consolidated total leverage ratio was
4.79
and our interest coverage ratio was
5.04
, which were both in compliance with the related requirements of our Credit Agreement. Our ability to maintain compliance with the 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. See Note 12 -
Debt Obligations
to our condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report for further discussion of the Credit Agreement.
We use the term “revolving credit facility” or “Credit Agreement,” we are referring to our First Amended and Restated Credit Facility and to our Second Amended and Restated Credit Facility, as the context may require.
JPE Revolver
JPE had a
$275.0 million
revolving loan, which included a sub-limit of up to
$100.0 million
for letters of credit with Bank of America, N.A. (the “JPE Revolver”). The JPE Revolver was scheduled to mature on February 12, 2019, but on March 8, 2017, in connection with the closing of the JPE acquisition, the
$199.5 million
outstanding balance of the JPE Revolver was paid off in full and terminated. For the
six months ended June 30,
2017
and
2016
, the weighted average interest rate on borrowings under our Credit Agreement and the JPE Revolver was approximately
4.67%
and
4.15%
, respectively.
8.50% Senior Unsecured Notes
On December 28, 2016, the Issuers completed the issuance and sale of the 8.50% Senior Notes. The 8.50% Senior Notes rank equal in right of payment with all existing and future senior indebtedness of the Issuers, and senior in right of payment to any future subordinated indebtedness of the Issuers. The 8.50% Senior Notes were issued at par and provided approximately $294.0 million in proceeds, after deducting the initial purchasers' discount of $6.0 million. This amount was deposited into escrow pending completion of the JPE Acquisition and is included in
Restricted cash-long
term on our consolidated balance sheet as of December 31, 2016. We also incurred $2.7 million of debt issuance costs resulting in net proceeds related to the 8.50% Senior Notes of $291.3 million. The 8.50% Senior notes were offered and sold to qualified institutional buyers in the United States pursuant to Rule 144A under the Securities Act, and to persons, other than U.S. persons, outside the United States pursuant to Regulation S under the Securities Act.
Upon the closing of the JPE Acquisition and the satisfaction of other conditions related thereto, the proceeds were used to repay and terminate the JPE Revolver and reduce borrowings under our Credit Agreement.
The 8.50% Senior Notes will mature on December 15, 2021 with interest payable in cash semi-annually in arrears on June 15 and December 15, commencing June 15, 2017. See Note 12 -
Debt Obligations
to our condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report for further discussion of the 8.50% Senior Notes.
3.77% Senior Secured Notes
On September 30, 2016, Midla Financing (“Midla Financing”) American Midstream (Midla) LLC (“Midla”), and Mid Louisiana Gas Transmission LLC (“MLGT” and together with Midla, the “Note Guarantors”) entered into the 3.77% Senior Note Purchase and Guaranty Agreement (the “Note Purchase Agreement”) with the purchasers party thereto (the “Purchasers”). Pursuant to the Note Purchase Agreement, Midla Financing issued and sold $60.0 million in aggregate principal amount of 3.77% Senior Notes (non-recourse) due June 30, 2031 (the “3.77% Senior Notes”) to the Purchasers, which bear interest at an annual rate of 3.77% to be paid quarterly. The average quarterly principal payment is approximately $1.1 million. Principal on the 3.77% Senior Notes will be paid on the last business day of each fiscal quarter end starting June 30, 2017. The 3.77% Senior Notes are payable in full on June 30, 2031. The 3.77% Senior Notes were issued at par and provided net proceeds of approximately
$49.8 million
(after deducting related issuance costs). The proceeds are contractually restricted. The 3.77% Senior Notes are non-recourse to the Partnership.
In connection with the Note Purchase Agreement, the Note Guarantors guaranteed the payment in full of all Midla Financing’s obligations under the 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 Financing Holdings pledged the membership interests in Midla Financing to the Collateral Agent.
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 (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. See Note 12 -
Debt Obligations
to our condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report on further discussion of the 3.77% Senior Notes.
Acquisition Support and Reimbursement
In recognition of the historically warm weather that adversely impacted the Propane Marketing Services segment and the transition-related impacts of the JPE Acquisition during the quarter, affiliates of ArcLight, the owner of our general partner agreed to absorb
$9.6 million
corporate overhead expenses, which were incurred by us in the first quarter of 2017 and subsequently paid the amount in the second quarter of 2017. This is incremental to the commitments made in the support agreement with the Partnership that was executed in conjunction with the JPE Acquisition.
Working Capital
Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and
accounts payable are impacted by the same commodity prices. In addition, the timing of payments received from our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger suppliers and customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors. Our working capital was
$9.5 million
at
June 30, 2017
, compared with a working capital deficit of
$16.4 million
at December 31, 2016.
Cash Flows
The following table reflects cash flows for the applicable periods (in thousands):
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Six months ended June 30,
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2017
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2016
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Net cash provided by (used in):
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Operating activities
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$
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25,276
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$
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49,716
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Investing activities
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232,315
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(141,976
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)
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Financing activities
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(257,354
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)
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92,314
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Net cash increase in cash and cash equivalents
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$
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237
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$
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54
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Six Months Ended
June 30, 2017
Compared to
Six Months Ended
June 30, 2016
Operating Activities
. During the
six months ended June 30, 2017
, we had
$25.3 million
of cash provided by operating activities, a
decrease
of
$24.4 million
when compared to
$49.7 million
of cash provided by operating activities in the same period in 2016. The decrease in cash flows from operating activities resulted primarily from an increase of our net loss year over year by
$36.5 million
driven primarily by our transition costs, interest expense and merger-related expenses, offset by changes in non-cash add backs of approximately $10.0 million, primarily in depreciation, amortization and accretion, amortization of deferred financing costs and bad debt expenses.
Investing Activities
. During the
six months ended June 30, 2017
, net cash provided by investing activities was
$232.3 million
, an
increase
of
$374.3 million
as compared to net cash used in investing activities of
$142.0 million
in the same period of 2016. The increase of cash flows from investing activities resulted primarily from the release of $299.3 million in restricted cash in March 2017 that was recorded since the end of 2016 and held in escrow and acquisitions of $100.9 million of investments in unconsolidated affiliates in the
six months ended June 30, 2016
, with no such comparable activity related to acquisitions in the same period in 2017.
Financing Activities
. During the
six months ended June 30, 2017
, net cash used in financing activities was
$257.4 million
, a
decrease
of
$349.7 million
as compared to net cash provided by financing activities of
$92.3 million
in the same period in 2016. The decrease in cash flows from financing activities resulted primarily from a decrease of
$71.5 million
in borrowings on the revolving credit facility, an increase of
$282.0 million
in repayments on the revolving credit facility and an increase of
$6.5 million
in distributions made to unitholders. Partially offsetting these items was an increase in contributions from unitholders of
$21.3 million
.
Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. At
June 30, 2017
, our material off-balance sheet arrangements and transactions included operating lease arrangements and service contracts. There are no other transactions, arrangements, or other relationships associated with our investments in unconsolidated affiliates or related parties that are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources. At
June 30, 2017
, our off-balance sheet arrangements totaled $37.6 million.
Capital Requirements
The energy business is capital intensive, requiring significant investment for the maintenance of existing assets and the acquisition and development of new systems and facilities. We categorize our capital expenditures as either:
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•
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maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets) made to maintain our operating income or operating capacity; or
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•
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expansion capital expenditures, incurred for acquisitions of capital assets or capital improvements that we expect will increase our operating income or operating capacity over the long term.
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Historically, our maintenance capital expenditures have not included all capital expenditures required to maintain volumes on our systems. It is customary in the regions in which we operate for producers to bear the cost of well connections, but we cannot be assured that this will be the case in the future. For the three months ended June 30, 2017, capital expenditures totaled
$24.1 million
, including expansion capital expenditures of
$21.6 million
, maintenance capital expenditures of
$2.1 million
and reimbursable project expenditures (capital expenditures for which we expect to be reimbursed for all or part of the expenditures by a third party) of
$0.4 million
. For the six months ended June 30, 2017, capital expenditures totaled
$44.3 million
, including expansion capital expenditures of
$37.7 million
, maintenance capital expenditures of
$4.2 million
and reimbursable project expenditures (capital expenditures for which we expect to be reimbursed for all or part of the expenditures by a third party) of
$2.5 million
. Although we classified our capital expenditures as expansion and maintenance, we believe those classifications approximate, but do not necessarily correspond to, the definitions of estimated maintenance capital expenditures and expansion capital expenditures under our Partnership Agreement.
Distributions
We intend to pay a quarterly distribution for the foreseeable future although we do not have a legal obligation to make distributions except as provided in our Partnership Agreement.
On
July 25, 2017
, 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
June 30, 2017
, or
$1.65
per common unit on an annualized basis. The cash distribution is expected to be paid on
August 14, 2017
, to unitholders of record as of the close of business on
August 7, 2017
.
Critical Accounting Policies
There were no changes to our critical accounting policies from those disclosed in our Annual Report on Form 10-K filed on March 28, 2017.
Recent Accounting Pronouncements
For information regarding new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements, refer to Note 2
- New Accounting Pronouncements
in Part I, Item 1 of this Quarterly Report, which is incorporated herein by reference.