UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the quarterly period ended September 30, 2016

OR

For the transition period from            to           

Commission File Number: 001-33303

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)

 

 

(713) 584-1000

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑ No ☐

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

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑.

As of October 31, 2016, there were 243,520,639 common units representing limited partner interests and 4,969,807 general partner units outstanding. As of October 31, 2016, there were 5,000,000 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units outstanding.

 

 

 

 

 

 

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PART I—FINANCIAL INFORMATION

 

 

 

 

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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Targa Resources Partners LP’s (together with its subsidiaries, “we,” “us,” “our,” “TRP” or “the Partnership”) 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 within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, by the use of forward-looking statements, 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. Known risks and uncertainties include, but are not limited to, the following risks and uncertainties:

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 other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in “Part II- Other Information, Item 1A. Risk Factors.” in this Quarterly Report and in our Annual Report. Except as may be required by applicable law, 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.

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As generally used in the energy industry and in this Quarterly Report, the identified terms have the following meanings:

 

 

 

 

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements.

TARGA RESOURCES PARTNERS LP

CONSOLIDATED BALANCE SHEETS

 

 

 

 

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TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

 

 

See notes to consolidated financial statements.

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TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

 

 

See notes to consolidated financial statements.

 

 

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TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY

 

 

See notes to consolidated financial statements.

 

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TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

See notes to consolidated financial statements.

 

 

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TARGA RESOURCES PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

(Unaudited)

 

The year-end condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.

 

 

Note 1 — Organization and Operations

Our Organization

Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by our parent, Targa Resources Corp. (“Targa” or “TRC” or the “Company” or “Parent”). In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries.

On February 17, 2016, TRC completed the previously announced transactions contemplated by the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement”, and such transaction, the “TRC/TRP Merger”), by and among us, Targa Resources GP LLC (our “general partner” or “TRP GP”), TRC and Spartan Merger Sub LLC, a subsidiary of TRC (“Merger Sub”), pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the Merger Agreement, Merger Sub merged with and into TRP (the “TRC/TRP Merger”), with TRP continuing as the surviving entity and as a subsidiary of TRC. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units.

At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of common stock of TRC, par value $0.001 per share (“TRC shares”). No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares.

Pursuant to the TRC/TRP Merger Agreement, TRC has agreed to cause our common units to be delisted from the New York Stock Exchange (“NYSE”) and deregistered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). As a result of the completion of the TRC/TRP Merger, our common units are no longer publicly traded. The 5,000,000 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.”

 

Subsequent Event

 

On October 19, 2016, we executed the Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (the “Third A&R Partnership Agreement”), which will be effective as of December 1, 2016. The Third A&R Partnership Agreement amendments include among other things (i) eliminating the IDRs held by the general partner, and related distribution and allocation provisions, (ii) eliminating the Special GP Interest (as defined in the Third A&R Partnership Agreement) held by the general partner, (iii) providing the ability to declare monthly distributions in addition to quarterly distributions, (iv) modifying certain provisions relating to distributions from available cash, (v) eliminating the Class B Unit (as defined in the Third A&R Partnership Agreement) provisions and (vi) changes to the Third A&R Partnership Agreement to reflect the passage of time and to remove provisions that are no longer applicable.

Our Operations

We are engaged in the business of:

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Areas of gathering and processing operations include the Permian Basin in West Texas and Southeast New Mexico; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma and South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico. Our logistics and marketing assets are predominately located in Mont Belvieu and Galena Park, TX, Lake Charles, LA, and Tacoma, WA. See Note 17 – Segment Information for certain financial information for our business segments.

The employees supporting our operations are employed by Targa. Our consolidated financial statements include the direct costs of Targa employees deployed to our operating segments, as well as an allocation of costs associated with our usage of Targa’s centralized general and administrative services.

 

 

Note 2 — Basis of Presentation

We have prepared these unaudited consolidated financial statements in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. While we derived the year-end balance sheet data from audited financial statements, this interim report does not include all disclosures required by GAAP for annual periods. These unaudited consolidated financial statements and other information included in this Quarterly Report should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report.

The unaudited consolidated financial statements for the three and nine months ended September 30, 2016 and 2015, include all adjustments that we believe are necessary for a fair statement of the results for interim periods. All significant intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods may have been reclassified to conform to the current year presentation.

Our financial results for the three and nine months ended September 30, 2016 are not necessarily indicative of the results that may be expected for the full year.

As described in Note 4 – Business Acquisitions, the February 27, 2015 Atlas mergers involved two separate legal transactions involving different groups of equity holders. For GAAP reporting purposes, these two mergers are viewed as a single integrated transaction. As such, the financial effects of the Targa consideration related to the ATLS merger have been reflected in these financial statements. As further described in Note 4 – Business Acquisitions, our partnership agreement (the “Partnership Agreement”) was amended to provide for the issuance of the Special GP Interest in us equal to the tax basis of the APL GP Interests acquired in the ATLS merger totaling $1.6 billion. The Special GP Interest is not entitled to current distributions or allocations of net income or loss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL GP and the right to distributions in liquidation.

 

Revisions of Previously Reported Activity in our Consolidated Statements of Comprehensive Income (Loss)

 

During the first quarter of 2016 we concluded that activity related to our commodity hedge contracts was not reported properly in our Consolidated Statements of Comprehensive Income (Loss) during 2015.  The errors resulted in misstatements of the statement caption “Change in fair value” and equal offsetting misstatements of the caption “Settlements reclassified to revenues.”  Related income tax effects were also misstated.

 

We concluded that these misstatements were not material to any of the periods affected, as reported “Total Other Comprehensive Income” is unchanged.  However, we have revised previous Consolidated Statements of Comprehensive Income (Loss) reported during 2015 to properly reflect changes in fair value and settlements reclassified to revenues. There is no impact on previously reported net income, total comprehensive income, cash flows, financial position or other profitability measures.

 

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The following table displays the impact of these revisions to activity reported in our Consolidated Statements of Comprehensive Income (Loss) during the three and nine months ended September 30, 2015 and the year ended December 31, 2015.

 

 

 

Note 3 — Significant Accounting Policies

Accounting Policy Updates

The accounting policies that we follow are set forth in Note 3 – Significant Accounting Policies of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K. There were no significant updates or revisions to our policies during the nine months ended September 30, 2016, except as noted below.

Recent Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The update also creates a new Subtopic 340-40, Other Assets and Deferred Costs – Contracts with Customers, which provides guidance for the incremental costs of obtaining a contract with a customer and those costs incurred in fulfilling a contract with a customer that are not in the scope of another topic. The new revenue standard requires that entities should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entities expect to be entitled in exchange for those goods or services. To achieve that core principle, the standard requires a five step process of identifying the contracts with customers, identifying the performance obligations in the contracts, determining the transaction price, allocating the transaction price to the performance obligations, and recognizing revenue when, or as, the performance obligations are satisfied. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

 

With the issuance in August 2015 of ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, the revenue recognition standard is effective for the annual period beginning after December 15, 2017, and for annual and interim periods thereafter. Earlier adoption is permitted for annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We must retroactively apply the new revenue recognition standard to transactions in all prior periods presented, but will have a choice between either (1) restating each prior period presented or (2) presenting a cumulative effect adjustment in the period the amendment is adopted.

In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations. The amendments in this update improve the operability and understandability of the implementation guidance on principal versus agent considerations, including clarifying that an entity should determine whether it is a principal or an agent for each specified good or service promised to a customer. These amendments are effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2017, with early adoption permitted.

In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. These amendments clarify the guidance on identification of performance obligations and licensing. The amendments include that entities do not have to decide if goods and services are performance obligations if they are considered immaterial in the context of a contract. Entities are also permitted to account for the shipping and handling that takes place after the customer has gained control of the goods as actions to fulfill the contract rather than separate services. In order to identify a

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performance obligation in a customer contract, an entity has to determine whether the goods or services are distinct, and ASU No. 2016-10 clarifies how the determination can be made.

In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients. These amendments address certain implementation issues related to assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition, and also provide additional practical expedients.

We expect to adopt these updates in their entirety on January 1, 2018, and are continuing to evaluate the impact on our revenue recognition practices.

Consolidation

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The amendments are intended to simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities and modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities. The amendments were effective for us in 2016 with no impact on our consolidated financial statements.

 

Presentation of Debt Issuance Costs

 

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The amendments in this update require that debt issuance costs related to a recognized debt liability (other than line-of-credit or other revolving credit facilities) be presented in the Consolidated Balance Sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This update dealt solely with financial statement display matters; recognition and measurement of debt issuance costs were unaffected. We adopted the amendments on January 1, 2016 and have reclassified unamortized debt issuance costs of $38.3 million on our Consolidated Balance Sheet as of December 31, 2015 from Other long-term assets to Long-term debt to conform to current year presentation. Our Consolidated Balance Sheet as of September 30, 2016 has $29.4 million in unamortized debt issuance costs classified in Long-term debt.

Leases

 

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We expect to adopt the amendments in the first quarter of 2019 and are currently evaluating the impacts of the amendments to our consolidated financial statements and accounting practices for leases.

Share-Based Compensation

 

In March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The amendments in this update provide, among other things, that (1) all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit in the income statement with the tax effects of exercised or vested awards treated as discrete items in the reporting period in which they occur and recognition of excess tax benefits regardless of whether the benefit reduces taxes payable in the current period; (2) excess tax benefits should be classified along with other income tax cash flows as an operating activity; (3) an entity can make an entity-wide accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur; (4) the threshold to qualify for equity classification permits withholding up to the maximum statutory tax rates in the applicable jurisdictions; and (5) cash paid by an employer when directly withholding shares for tax-withholding purposes should be classified as a financing activity on the statement of cash flows. We adopted the applicable amendments in the second quarter of 2016; however there was no impact to our consolidated financial statements.

Measurement of Credit Losses on Financial Instruments

 

In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. These amendments change the measurement of credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The amendments in this update affect investments in loans,

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investments in debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. The amendments replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. We expect to adopt this guidance on January 1, 2019, and are continuing to evaluate the impact on our measurement of credit losses.

Cash Flow Classification

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). These amendments clarify how entities should classify certain cash receipts and cash payments on the statement of cash flows related to the following transactions: (1) debt prepayment or extinguishment costs; (2) settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing; (3) contingent consideration payments made after a business combination; (4) proceeds from the settlement of insurance claims; (5) proceeds from the settlement of corporate-owned life insurance; (6) distributions received from equity method investees; and (7) beneficial interests in securitization transactions. Additionally, the update clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the effect of the amendments on our consolidated financial statements and related disclosures.

 

Recognition of Intra-Entity Transfers of Assets Other than Inventory

In October 2016, the FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory. The amendments in this update are intended to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party which is an exception to the principle of comprehensive recognition of current and deferred income taxes in GAAP. This update eliminates the exception by requiring entities to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the effect of the amendments on our consolidated financial statements and related disclosures.

 

 

Note 4 – Business Acquisitions

2015 Acquisition

Atlas Mergers

On February 27, 2015, Targa completed the transactions contemplated by the Agreement and Plan of Merger, dated as of October 13, 2014 (the “ATLS Merger Agreement”), by and among (i) Targa, Targa GP Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of Targa (“GP Merger Sub”), Atlas Energy L.P., a Delaware limited partnership (“ATLS”) and Atlas Energy GP, LLC, a Delaware limited liability company and the general partner of ATLS (“ATLS GP”), and (ii) Targa and the Partnership completed the transactions contemplated by the Agreement and Plan of Merger (the “APL Merger Agreement” and, together with the ATLS Merger Agreement, the “Atlas Merger Agreements”) by and among Targa, the Partnership, the Partnership’s general partner, Trident MLP Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of the Partnership (“MLP Merger Sub”), ATLS, Atlas Pipeline Partners L.P., a Delaware limited partnership (“APL”) and Atlas Pipeline Partners GP, LLC, a Delaware limited liability company and the general partner of APL (“APL GP”). Pursuant to the terms and conditions set forth in the ATLS Merger Agreement, GP Merger Sub merged (the “ATLS merger”) with and into ATLS, with ATLS continuing as the surviving entity and as a subsidiary of Targa. Pursuant to the terms and conditions set forth in the APL Merger Agreement, MLP Merger Sub merged (the “APL merger” and, together with the ATLS merger, the “Atlas mergers”) with and into APL, with APL continuing as the surviving entity and as a subsidiary of the Partnership. While the Atlas mergers were two separate legal transactions, for GAAP reporting purposes, they are viewed as a single integrated transaction. As such, the financial effects of the ATLS Merger Consideration (as defined below) paid by Targa have been reflected in these financial statements. In connection with the Atlas mergers, APL changed its name to “Targa Pipeline Partners LP,” which we refer to as TPL, and ATLS changed its name to “Targa Energy LP.”

 

In addition, prior to the completion of the Atlas mergers, ATLS, pursuant to a separation and distribution agreement entered into by and among ATLS, ATLS GP and Atlas Energy Group, LLC, a Delaware limited liability company (“AEG”), on February 27, 2015, (i) transferred its assets and liabilities other than those related to its “Atlas Pipeline Partners” segment, to AEG and (ii) effected a pro

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rata distribution to the ATLS unitholders of AEG common units representing a 100% interest in AEG (collectively, the “Spin-Off” and, together with the Atlas mergers, the “Atlas Transactions”).

On February 27, 2015, the Partnership Agreement was amended to provide for the issuance of a special general partner interest in the Partnership (the “Special GP Interest”) representing the contribution to the Partnership of the APL GP interest acquired in the ATLS merger totaling $1.6 billion, which is reflected within General partner equity on the Consolidated Balance Sheets. The Special GP Interest is not entitled to current distributions or allocations of net income or loss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL GP and the right to distributions in liquidation.

We acquired all of the outstanding units of APL for a total purchase price of approximately $5.3 billion (including $1.8 billion of acquired debt and all other assumed liabilities). Of the $1.8 billion of debt acquired and other liabilities assumed, approximately $1.2 billion of the acquired debt was tendered and settled upon the closing of the Atlas mergers via our January 2015 cash tender offers. These tender offers were in connection with, and conditioned upon, the consummation of the merger with APL. The merger with APL, however, was not conditioned on the consummation of the tender offers. On that same date, Targa acquired ATLS for a total purchase price of approximately $1.6 billion (including all assumed liabilities).

Pursuant to the APL Merger Agreement, our general partner entered into an amendment to our Partnership Agreement, which we refer to as the IDR Giveback Amendment, in order to reduce aggregate distributions to TRC, as the holder of the Partnership’s incentive distribution rights (“IDRs”) by (a) $9,375,000 per quarter during the first four quarters following the APL merger, (b) $6,250,000 per quarter for the next four quarters, (c) $2,500,000 per quarter for the next four quarters and (d) $1,250,000 per quarter for the next four quarters, with the amount of such reductions to be distributed pro rata to the holders of our outstanding common units.

TPL is a provider of natural gas gathering, processing and treating services primarily in the Anadarko, Arkoma and Permian Basins located in the southwestern and mid-continent regions of the United States and in the Eagle Ford Shale in South Texas. The Atlas mergers added TPL’s Woodford/SCOOP, Mississippi Lime, Eagle Ford and additional Permian assets to the Partnership’s existing operations. In total, TPL added 2,053 MMcf/d of processing capacity and 12,220 miles of additional pipeline. The operating results of TPL are reported in our Gathering and Processing segment.

The APL merger was a unit-for-unit transaction with an exchange ratio of 0.5846 of our common units (the “APL Unit Consideration”) and $1.26 in cash for each APL common unit (the “APL Cash Consideration” and, with the APL Unit Consideration, the “APL Merger Consideration”), a $128.0 million total cash payment, of which $0.6 million was expensed at the acquisition date as the cash payment representing accelerated vesting of a portion of retained employees’ APL phantom awards. We issued 58,614,157 of our common units and awarded 629,231 replacement phantom unit awards with a combined value of approximately $2.6 billion as consideration for the APL merger (based on the $43.82 closing market price of a common unit on the NYSE on February 27, 2015). The cash component of the APL merger also included $701.4 million for the mandatory repayment and extinguishment at closing of the APL Senior Secured Revolving Credit Facility that was to mature in May 2017 (the “APL Revolver”), $28.8 million of payments related to change of control and $6.4 million of cash paid in lieu of unit issuances in connection with settlement of APL equity awards for AEG employees. In March 2015, Targa contributed $52.4 million to us to maintain its 2% general partner interest.

In addition, pursuant to the APL Merger Agreement, APL exercised its right under the certificate of designations of the APL 8.25% Class E cumulative redeemable perpetual preferred units (“Class E Preferred Units”) to redeem the APL Class E Preferred Units immediately prior to the effective time of the APL merger.

The ATLS merger was a stock-for-unit transaction with an exchange ratio of 0.1809 of Targa common stock, par value $0.001 per share (the “ATLS Stock Consideration”), and $9.12 in cash for each ATLS common unit (the ATLS Cash Consideration” and, with the ATLS Stock Consideration, the “ATLS Merger Consideration”), (a $514.7 million total cash payment). Targa issued 10,126,532 of its common shares and awarded 81,740 replacement restricted stock units with a combined value of approximately $1.0 billion for the ATLS merger (based on the $99.58 closing market price of a TRC common share on the NYSE on February 27, 2015). The cash component of the ATLS merger also included approximately $149.2 million of payments related to change of control and cash settlements of equity awards, $88.0 million for repayment of a portion of ATLS outstanding indebtedness and $11.0 million for reimbursement of certain transaction expenses. Approximately $4.5 million of the one-time cash payments and cash settlements of equity awards, which represent accelerated vesting of a portion of retained employees’ ATLS phantom units, were expensed at the acquisition date.

ATLS owned, directly and indirectly, 5,754,253 APL common units immediately prior to closing. Targa’s acquisition of ATLS resulted in Targa acquiring these common units (converted to 3,363,935 of our common units) valued at approximately $147.4 million (based on the $43.82 closing market price of our common units on the NYSE on February 27, 2015) and the right to receive the units’ one-time cash payment of approximately $7.3 million, which reduced the consolidated purchase price by approximately $154.7 million.

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All outstanding ATLS equity awards, whether vested or unvested, were adjusted in connection with the Spin-Off on the terms and conditions set forth in an Employee Matters Agreement entered into by ATLS, ATLS GP and AEG on February 27, 2015. Following the Spin-Off-related adjustment and at the effective time of the ATLS merger, each outstanding ATLS option and ATLS phantom unit award, whether vested or unvested, held by a person who became an employee of AEG became fully vested (to the extent not vested) and was cancelled and converted into the right to receive the ATLS Merger Consideration in respect of each ATLS common unit underlying the ATLS option or phantom unit award (in the case of options, net of the applicable exercise price). Each outstanding vested ATLS option held by an employee of APL who became an employee of Targa in connection with the Atlas Transactions (a “Midstream Employee”) was cancelled and converted into the right to receive the ATLS Merger Consideration in respect of each ATLS common unit underlying the vested ATLS option, net of the applicable exercise price. Each outstanding unvested ATLS option and each outstanding ATLS phantom unit award held by a Midstream Employee was cancelled and converted into the right to receive (1) the ATLS Cash Consideration in respect of each ATLS common unit underlying such ATLS option or phantom unit award and (2) a TRC restricted stock unit award with respect to a number of shares of TRC Common Stock equal to the product of the ATLS Stock Consideration multiplied by the number of ATLS common units underlying such ATLS option or phantom unit award (in the case of options, net of the applicable exercise price).

In connection with the APL merger, each outstanding APL phantom unit award held by an employee of AEG became fully vested and was cancelled and converted into the right to receive the APL Merger Consideration in respect of each APL common unit underlying the APL phantom unit award. Each outstanding APL phantom unit award held by a Midstream Employee was cancelled and converted into the right to receive (1) the APL Cash Consideration in respect of each APL common unit underlying such APL phantom unit award and (2) a Partnership phantom unit award with respect to a number of our common units equal to the product of the APL Unit Consideration multiplied by the number of APL common units underlying such APL phantom unit award.

The acquired business contributed revenues of $1,065.7 million and a net loss of $1.0 million to us for the period from February 27, 2015 to September 30, 2015, and is reported in our Gathering and Processing segment. As of September 30, 2015, we had incurred $19.3 million of acquisition-related costs. These expenses are included in other expense in our Consolidated Statements of Operations for the nine months ended September 30, 2015. As of September 30, 2016, cumulative acquisition-related costs totaled $19.4 million.

Pro Forma Impact of Atlas Mergers on Consolidated Statement of Operations

The following summarized unaudited pro forma Consolidated Statement of Operations information for the nine months ended September 30, 2015 assumes that our acquisition of APL and Targa’s acquisition of ATLS had occurred as of January 1, 2014. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma financial results may not be indicative of the results that would have occurred if we had completed the APL merger as of January 1, 2014, or that the results that will be attained in the future. Amounts presented below are in millions:

 

 

The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making adjustments to:

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The following table summarizes the consideration transferred to acquire ATLS and APL, which are viewed together as a single integrated transaction for GAAP reporting purposes:

 

 

Our final fair value determination related to the Atlas mergers was as follows:

 

 

During the three months ended June 30, 2015, we recorded measurement-period adjustments to our acquisition date fair values due to the refinement of our valuation models, assumptions and inputs. As a result, the Consolidated Statement of Operations for the three months ended March 31, 2015 was retrospectively adjusted for the impact of measurement-period adjustments to property, plant and equipment, intangible assets, and investments in unconsolidated affiliates. These adjustments resulted in a decrease in depreciation and amortization expense of $1.0 million, and an increase in equity earnings of $0.3 million from the amounts previously reported in our Form 10-Q for the quarter ended March 31, 2015.

During the three months ended September 30, 2015, we recorded additional measurement-period adjustments to our acquisition date fair values due to the refinement of our valuation models, assumptions and inputs. In accordance with ASU 2015-16, we recognized these measurement-period adjustments in the third quarter of 2015, with the effect on the Consolidated Statements of Operations

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resulting from the change to the provisional amounts calculated as if the acquisition had been completed at February 27, 2015. During the three months ended September 30, 2015, the acquisition date fair value of property, plant and equipment increased by $9.9 million, investments in unconsolidated affiliates increased by $5.5 million, intangible assets decreased by $5.0 million, current liabilities increased by $2.4 million, other assets decreased by $1.0 million, and other current assets decreased by $0.6 million, which resulted in a decrease in goodwill of $6.4 million. These adjustments resulted in increased revenues of $0.6 million, a reduction of operating expenses of $1.9 million, depreciation and amortization expense of $0.1 million and equity losses of $0.1 million recorded in the three months ended September 30, 2015, which, under the prior accounting standard, would have been reflected in previous reporting periods.

During the three months ended December 31, 2015, we recorded additional measurement-period adjustments to our acquisition date fair values due to the refinement of our valuation models, assumptions and inputs, as well as adjustments to previously reported preliminary fair values as a result of our review procedures over the development and application of inputs, assumptions and calculations used in cash-flow based fair value measurements associated with business combinations not operating as designed (as previously disclosed in our 2015 Annual Report on Form 10-K). We recognized these adjustments in the fourth quarter of 2015, with the effect on the Consolidated Statements of Operations resulting from the change to the provisional amounts calculated as if the acquisition had been completed at February 27, 2015. During the three months ended December 31, 2015, the acquisition date fair value of intangible assets increased $155.9 million, noncontrolling interest in subsidiaries increased $103.5 million, other long-term liabilities increased $110.1 million, property, plant and equipment decreased by $86.2 million, investments in unconsolidated affiliates decreased by $5.2 million, deferred tax liabilities increased by $5.0 million, current liabilities increased by $1.3 million, other assets decreased by $0.1 million and other current assets decreased by $0.1 million, which resulted in an increase in goodwill of $155.6 million. These adjustments resulted in depreciation and amortization expenses of $2.0 million, a net decrease to interest expense of $26.2 million, equity earnings of $0.2 million, and a reduction of general and administrative expenses of $0.4 million, recorded in the three months ended December 31, 2015, which, under the prior accounting standard, would have been reflected in previous reporting periods.

The valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions including projections of future production volumes and cash flows, benchmark analysis of comparable public companies, expectations regarding customer contracts and relationships, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 13 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation.

The excess of the purchase price over the fair value of net assets acquired was approximately $707.0 million which was recorded as goodwill. The determination of goodwill is attributable to the workforce of the acquired business and the expected synergies with us and Targa. The goodwill is amortizable for tax purposes.

The fair value of assets acquired included trade receivables of $178.1 million. The gross amount due under contracts was $178.1 million, all of which was expected to be collectible. The fair value of assets acquired included other receivables of $3.0 million reported in current receivables and $4.5 million reported in other long-term assets related to a contractual settlement with a counterparty.

Mandatorily Redeemable Preferred Interests  

Other long-term liabilities acquired included $109.3 million related to mandatorily redeemable preferred interests held by our partner in two joint ventures (see Note 10 – Other Long-Term Liabilities).

Contingent Consideration

A liability arising from the contingent consideration for APL’s previous acquisition of a gas gathering system and related assets has been recognized at fair value. APL agreed to pay up to an additional $6.0 million if certain volumes are achieved on the acquired gathering system within a specified time period. The fair value of the remaining contingent payment is recorded within other long term liabilities on our Consolidated Balance Sheets. The range of the undiscounted amount that we could pay related to the remaining contingent payment is between $0.0 and $6.0 million. We finalized our acquisition analysis and modeling of this contingent liability during the three months ended June 30, 2015, which resulted in an acquisition date fair value of $4.2 million. Subsequent changes in the fair value of this liability are included in earnings.

Replacement Phantom Units

In connection with the Atlas mergers, we awarded replacement phantom units in accordance with and as required by the Atlas Merger Agreements to those APL employees who became Targa employees after the acquisition. The vesting dates and terms remained

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unchanged from the existing APL awards, and vest over the remaining terms of the awards, which are either 25% per year over the original four year term or 33% per year over the original three year term.

Each replacement phantom unit will entitle the grantee to common stock of TRC on the vesting date and is an equity-settled award. The replacement phantom units include distribution equivalent rights (“DERs”). When we declare and pay cash distributions, the holders of replacement phantom units are entitled within 60 days to receive cash payment of DERs in an amount equal to the cash distributions the holders would have received if they were the holders of record on the record date of the number of our common units related to the replacement phantom units.

The fair value of the replacement phantom units was based on the closing price of our units at the close of trading on February 27, 2015. The fair value was allocated between the pre-acquisition and post-acquisition periods to determine the amount to be treated as purchase consideration and compensation expense, respectively. Compensation cost will be recognized in general and administrative expense over the remaining service period of each award.

Goodwill

We recognized goodwill at a fair value of approximately $707.0 million associated with the Atlas mergers as of the acquisition date on February 27, 2015. Goodwill has been attributed to the WestTX, SouthTX and SouthOK reporting units in our Gathering and Processing segment. As a result, any level of decrease in the forecasted cash flows from the date of acquisition would likely result in the fair value of the reporting unit to fall below the carrying value of the reporting unit, and could result in an impairment of that reporting unit’s goodwill.

As described in Note 3 – Significant Accounting Policies, we evaluate goodwill for impairment at least annually on November 30, or more frequently if we believe necessary based on events or changes in circumstances.  As of December 31, 2015, we had not completed our November 30, 2015 impairment assessment. Based on the results of that preliminary evaluation, we recorded a provisional goodwill impairment of $290.0 million during the fourth quarter of 2015. The provisional goodwill impairment reduced the carrying value of goodwill to $417.0 million on our Consolidated Balance Sheets as of December 31, 2015.

During the first quarter of 2016, we finalized our evaluation of goodwill for impairment and recorded additional impairment expense of $24.0 million in our Consolidated Statement of Operations and reduced the carrying value of goodwill to $393.0 million on our Consolidated Balance Sheets. The impairment of goodwill is primarily due to the effects of lower commodity prices, and a higher cost of capital for companies in our industry compared to conditions in February 2015 when we acquired Atlas. Our evaluation as of November 30, 2015 utilized the income approach (a discounted cash flow analysis (“DCF”)) to estimate the fair values of our reporting units. The future cash flows for our reporting units are based on our estimates, at that time, of future revenues, income from operations and other factors, such as working capital and capital expenditures. We take into account current and expected industry and market conditions, commodity pricing and volumetric forecasts in the basins in which the reporting units operate. The discount rates used in our DCF analysis are based on a weighted average cost of capital determined from relevant market comparisons.

Changes in the gross amounts of our goodwill are as follows:

 

 

The sustained decrease and uncertain outlook in commodity prices and volumes have adversely impacted our customers and their future capital and operating plans. A continued or prolonged period of lower commodity prices could result in further deterioration of reporting unit fair values and potential further impairment charges related to goodwill and property, plant and equipment. There were no impairment triggers identified or further impairment charges recognized in the third quarter of 2016.

 

Subsequent Event

 

On October 31, 2016, we executed a Membership Interest Sale and Purchase Agreement with Chevron U.S.A. Inc. to acquire their 37% membership interest in Versado Gas Processors, L.L.C. (“Versado”). Targa held a 63% controlling interest in Versado prior to this transaction and consolidated Versado. As we continue to control Versado, the change in our ownership interest will be accounted

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for as an equity transaction and no gain or loss will be recognized in our Consolidated Statements of Operations as a result.  See Note 15 – Contingencies.

 

 

 

Note 5 — Inventories

 

 

 

Note 6 — Property, Plant and Equipment and Intangible Assets

 

 

Intangible assets consist of customer contracts and customer relationships acquired in the Atlas mergers in 2015 and our Badlands business acquisition in 2012. The fair values of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. Key valuation assumptions include probability of contracts under negotiation, renewals of existing contracts, economic incentives to retain customers, past and future volumes, current and future capacity of the gathering system, pricing volatility and the discount rate.

The fair values of intangible assets acquired in the Atlas mergers have been recorded at a fair value of $1,354.9 million and are being amortized over a 20 year life using the straight-line method, as a reliably determinable pattern of amortization could not be identified. Amortization expense attributable to our intangible assets related to the Badlands acquisition is recorded using a method that closely reflects the cash flow pattern underlying their intangible asset valuation over a 20 year life.

 

The changes in our intangible assets are as follows:

 

 

Note 7 — Investments in Unconsolidated Affiliates

Our unconsolidated investments consist of a 38.8% non-operated ownership interest in Gulf Coast Fractionators LP (“GCF”) and three non-operated joint ventures in South Texas acquired in the Atlas mergers in 2015: 75% interest in T2 LaSalle; 50% interest in T2 Eagle Ford; and 50% interest in T2 EF Cogen (together the “T2 Joint Ventures”).  The T2 Joint Ventures were formed to provide services for the benefit of the joint interest owners. The T2 Joint Ventures have capacity lease agreements with the joint interest owners, which cover the costs of operations of the T2 Joint Ventures. The terms of these joint venture agreements do not afford us the degree of control required for consolidating them in our consolidated financial statements, but do afford us the significant influence required to employ the equity method of accounting. Our maximum exposure to loss as a result of our involvement with the T2 Joint Ventures includes our equity investment, any additional capital contribution commitments, and our share of any operating expenses incurred by the T2 Joint Ventures.

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The following table shows the activity related to our investments in unconsolidated affiliates:

 

 

The recorded value of the T2 Joint Ventures is based on fair values at the date of acquisition which results in an excess fair value of $36.7 million over the book value of the joint venture capital accounts as of September 30, 2016. This basis difference is attributable to depreciable tangible assets and is being amortized over the estimated useful lives of the underlying assets of 20 years on a straight-line basis and is included as a component of equity earnings. See Note 4 – Business Acquisitions for further information regarding the fair value determinations related to the Atlas mergers.

 

 

Note 8 — Accounts Payable and Accrued Liabilities

 

 

Accounts payable and accrued liabilities includes $23.4 million and $34.0 million of liabilities to creditors to whom we have issued checks that remain outstanding as of September 30, 2016 and December 31, 2015.

 

 

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Note 9 — Debt Obligations

 

 

The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the nine months ended September 30, 2016:

 

 

Compliance with Debt Covenants

As of September 30, 2016, we were in compliance with the covenants contained in our various debt agreements.

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Debt Repurchases

During the nine months ended September 30, 2016, we repurchased on the open market a portion of our outstanding senior notes (the “Senior Notes”) as follows:

 

 

We may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. See “Subsequent Events – Issuance of Senior Notes and Concurrent Senior Notes Tender Offers” and “Subsequent Events – Note Redemptions.”

 

The following table shows the contractually scheduled maturities of our Senior Notes as of September 30, 2016, for five consecutive years, and in total thereafter:

 

 

Subsequent Events

 

Issuance of Senior Notes and Concurrent Senior Notes Tender Offers

 

In October 2016, we issued $500.0 million of 5⅛% Senior Notes due February 2025 and $500.0 million of 5⅜% Senior Notes due February 2027 (collectively, the “2016 Senior Notes”), yielding net proceeds of approximately $496.2 million and $496.2 million, respectively. The 2016 Senior Notes have substantially similar terms and covenants as our other series of Senior Notes. The net proceeds from the offering of the 2016 Senior Notes (the “October 2016 Offering”), along with borrowings under the TRP Revolver were used to fund concurrent tender offers for certain other series of senior notes.

 

Concurrently with the October 2016 Offering, we commenced tender offers (the “Tender Offers”) to purchase for cash, subject to certain conditions, up to specified aggregate maximum purchase amounts of our 5% Senior Notes due January 2018 (the “5% Notes”), 6⅝% Senior Notes due October 2020 (the “6⅝% Notes”) and 6⅞% Senior Notes due February 2021 (the “6⅞% Notes” and together with the 5% Notes and 6⅝% Notes, the “Tender Notes”). The total consideration for each series of Tender Notes included a premium for each $1,000 principal amount of notes that was tendered as of the early tender date of October 5, 2016. The Tender Offers were fully subscribed and we accepted for purchase all Tender Notes that were validly tendered as of the early tender date.

 

The results of the Tender Offers, which closed in October 2016, were:

 

 

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As a result of the Tender Offers, we will record during the fourth quarter of 2016 a loss due to debt extinguishment of approximately $59.2 million comprised of the $41.8 million premium paid, the write-off of $5.8 million of debt issuance costs, $15.1 million of debt discounts and $3.5 million of debt premiums.

 

Note Redemptions

 

Subsequent to the closing of the Tender Offers in October 2016, we issued notices of full redemption (the “Note Redemptions”) to the trustees and noteholders of the 6⅝% Notes and the 6⅞% Notes for the note balances remaining after the Tender Offers. In addition, we issued notice of full redemption to the trustees of the 6⅝% APL Notes due October 2020. The redemption price for the 6⅝% Notes and the 6⅝% APL Notes due October 2020 was 103.313% of the principal amount, while the redemption price for the 6⅞% Notes was 103.438% of the principal amount. The aggregate principal amount outstanding of all three series of notes totaling $146.2 million will be redeemed on November 15, 2016 for a total redemption payment of $151.1 million, excluding accrued interest. The redemption date for each series of notes is November 15, 2016. As a result of the Note Redemptions, we will record during the fourth quarter of 2016 a loss due to debt extinguishment of approximately $9.7 million comprised of the $4.9 million premium paid, the write-off of $1.1 million of debt issuance costs, $4.2 million of debt discounts and $0.5 million of debt premiums.          

 

TRP Revolver Amendment

 

In October 2016, we entered into the Second Amendment and Restatement Agreement (the “Restatement”) to effectuate the Third Amended and Restated Credit Agreement (the “TRP Credit Agreement”). The TRP Credit Agreement amended and restated the TRP Revolver to extend the maturity date from October 2017 to October 2020. The available commitments under the TRP Revolver of $1.6 billion remained unchanged while our ability to request additional commitments increased from up to $300.0 million to up to $500.0 million. The TRP Revolver continues to bear interest costs that are dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA, and the covenants also remained substantially the same. The TRP Credit Agreement designates TPL and certain of its subsidiaries as “Restricted Subsidiaries” and provides for certain changes to occur upon our receiving an investment grade credit rating from Moody’s or S&P, including the release of the security interests in all collateral at our request. As a result of the TRP Credit Agreement, during the fourth quarter of 2016, we will record a partial write-off of $0.9 million of debt issuance costs associated with the TRP Revolver as a result of a change in syndicate members under the TRP Revolver. The remaining deferred debt issuance costs associated with the TRP Revolver along with debt issuance costs incurred with this amendment will be amortized on a straight-line basis over the life of the TRP Revolver.

 

Subsequent to entering into the TRP Credit Agreement, we executed supplemental indentures relating to all of our outstanding series of Senior Notes to designate TPL and those subsidiaries as Restricted Subsidiaries under the TRP Credit Agreement as guarantors of such Senior Notes.

 

 

Note 10 — Other Long-term Liabilities

Other long-term liabilities are comprised of the following obligations:

 

 

Asset Retirement Obligations

Our asset retirement obligations (“ARO”) primarily relate to certain gas gathering pipelines and processing facilities, and are included in our Consolidated Balance Sheets as a component of other long-term liabilities. The changes in our ARO are as follows:

 

 

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Mandatorily Redeemable Preferred Interests

Our consolidated financial statements include our interest in two joint ventures that, separately, own a 100% interest in the WestOK natural gas gathering and processing system and a 72.8% undivided interest in the WestTX natural gas gathering and processing system. Our partner in the joint ventures holds preferred interests in each joint venture that are redeemable: (i) at our or our partner’s election, on or after July 27, 2022; and (ii) mandatorily, in July 2037.

For reporting purposes under GAAP, an estimate of our partner’s interest in each joint venture is required to be recorded as if the redemption had occurred on the reporting date. Because redemption will not be required until at least 2022, the actual value of our partner’s allocable share of each joint venture’s assets at the time of redemption may differ from our estimate of redemption value as of September 30, 2016.

The following table shows the changes attributable to mandatorily redeemable preferred interests:

 

 

 

Note 11 — Partnership Units and Related Matters

TRC/TRP Merger

On February 17, 2016, TRC completed the TRC/TRP Merger, indirectly acquiring all of the outstanding common units not already owned by TRC and its subsidiaries. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units.

At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of TRC shares. No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares.

Pursuant to the TRC/TRP Merger Agreement, our common units were delisted from the NYSE and deregistered under the Exchange Act and our common units are no longer publicly traded. Our 5,000,000 Preferred Units remain outstanding as preferred limited partner interests in us and continue to trade on the NYSE.

 

Preferred Units

 

Distributions on our 5,000,000 Preferred Units are cumulative from the date of original issue in October 2015 and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of our general partner. Distributions on our Preferred Units are payable out of amounts legally available at a rate equal to 9.0% per annum. On and after November 1, 2020, distributions on our Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%.

The Preferred Units will, with respect to anticipated monthly distributions, rank:

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At any time on or after November 1, 2020, we may redeem the Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, we (or a third party with our prior written consent) may redeem the Preferred Units following certain changes of control, as described in our Partnership Agreement. If we do not (or a third party with our prior written consent does not) exercise this option, then the holders of the Preferred Units (“Preferred Unitholders”) have the option to convert the Preferred Units into a number of common units per Preferred Unit as set forth in our Partnership Agreement. If we exercise (or a third party with our prior written consent exercises) our redemption rights relating to any Preferred Units, the holders of those Preferred Units will not have the conversion right described above with respect to the Preferred Units called for redemption. Holders of Preferred Units have no voting rights except for certain exceptions set forth in our Partnership Agreement.

We paid $8.4 million of distributions to Preferred Unitholders during the nine months ended September 30, 2016. We have accrued distributions to our Preferred Unitholders of $0.9 million for the nine months ended September 30, 2016.

 

On October 17, 2016, the board of directors of our general partner declared a monthly cash distribution of $0.1875 per Preferred Unit for October 2016. This distribution will be paid on November 15, 2016.

 

Issuances of Common Units

During the nine months ended September 30, 2016, Targa made capital contributions to us of $1,191.0 million. Related to these capital contributions, we issued to Targa 58,621,036 common units, and Targa issued general partner units of 1,196,346 to maintain its 2% general partner interest.

 

Targa Resource Partners Long Term Incentive Plan

 

The TRC/TRP Merger did not trigger the acceleration of any time-based vesting of any of our outstanding long-term equity incentive compensation awards under the Targa Resource Partners Long-Term Incentive Plan. Upon completion of the TRC/TRP Merger, on February 17, 2016, Targa assumed, adopted and amended the Targa Resource Partners Long-Term Incentive Plan (“TRP LTIP”), and has changed the name of the plan to the Targa Resources Corp. Equity Compensation Plan (the “Plan”). All outstanding performance unit awards previously granted under the TRP LTIP, were converted and restated into comparable awards based on Targa’s common shares. Specifically, each outstanding performance unit award was converted and restated, effective as of the effective time of the TRC/TRP Merger, into an award to acquire, pursuant to the same time-based vesting schedule and forfeiture and termination provisions, a comparable number of Targa common shares determined by multiplying the number of performance units subject to each award by the exchange ratio in the TRC/TRP Merger (0.62), rounded down to the nearest whole share. The performance factor has been eliminated as it was based on the performance of our common units versus peer MLPs. All amounts previously credited as distribution equivalent rights under any outstanding performance unit award continue to remain so credited and will be payable on the payment date set forth in the applicable award agreement, subject to the same time-based vesting schedule previously included in the performance unit award, but without application of any performance factor.

 

 

The conversion on February 17, 2016 of outstanding equity-settled performance units and replacement phantom units outstanding to equity-settled restricted stock units and replacement phantom shares was considered modification of awards under ASC 718, Accounting for Stock-Based Compensation (“ASC 718”). The incremental change of $3.9 million in fair value between the original grant date fair value and the fair value as of February 17, 2016 will be recognized prospectively in general and administrative expense over the remaining service period of each award.

 

The conversion on February 17, 2016 of outstanding cash-settled performance units outstanding to cash-settled restricted stock units was considered modification of awards under ASC 718. The incremental change in fair value between the original grant date fair value and the fair value as of February 17, 2016 resulted in recognition of additional compensation costs during the first quarter of $4.8 million. The remaining compensation cost will be recognized in general and administrative expense over the remaining service period of each award.

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Distributions

In accordance with the Partnership Agreement, the Partnership must distribute all of its available cash, as defined in the Partnership Agreement, and as determined by the general partner, to Preferred Unitholders monthly and to common unitholders of record within 45 days after the end of each quarter. As a result of the TRC/TRP Merger, TRC is entitled to receive all available Partnership distributions after payment of preferred distributions each quarter. The following details the distributions declared or paid by the Partnership, net of the IDR Giveback, during 2016:

 

Note 12 — Derivative Instruments and Hedging Activities

The primary purpose of our commodity risk management activities is to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have hedged the commodity prices associated with a portion of our expected (i) natural gas equity volumes in our Gathering and Processing segment and (ii) NGL and condensate equity volumes predominately in our Gathering and Processing segment that result from percent-of-proceeds processing arrangements. These hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices. We have designated these derivative contracts as cash flow hedges for accounting purposes.

The hedges generally match the NGL product composition and the NGL delivery points of our physical equity volumes. Our natural gas hedges are a mixture of specific gas delivery points and Henry Hub. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations.

We hedge a portion of our condensate equity volumes using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This necessarily exposes us to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes.

As part of the Atlas mergers, outstanding APL derivative contracts with a fair value of $102.1 million as of the acquisition date were novated to us and included in the acquisition date fair value of assets acquired. Derivative settlements of $67.9 million and $20.9 million related to these novated contracts were received during the year ended December 31, 2015 and the nine months ended September 30, 2016. These settlements were reflected as a reduction of the acquisition date fair value of the APL derivative assets acquired and had no effect on results of operations.

The "off-market" nature of these acquired derivatives can introduce a degree of ineffectiveness for accounting purposes due to an embedded financing element representing the amount that would be paid or received as of the acquisition date to settle the derivative contract. The resulting ineffectiveness can either potentially disqualify the derivative contract in its entirety for hedge accounting or alternatively affect the amount of unrealized gains or losses on qualifying derivatives that can be deferred from inclusion in periodic net income. Additionally, for the three and nine months ended September 30, 2016, we recorded $0.3 million and $0.5 million of ineffectiveness losses related to otherwise qualifying APL derivatives, which are primarily natural gas swaps.

At September 30, 2016, the notional volumes of our commodity derivative contracts were:

 

 

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We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues.

Our derivative contracts are subject to netting arrangements that permit our contracting subsidiaries to net cash settle offsetting asset and liability positions with the same counterparty within the same Targa entity. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements. The following schedules reflect the fair values of our derivative instruments and their location in our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis:

 

 

The pro forma impact of reporting derivatives in our Consolidated Balance Sheets on a net basis is as follows:

 

 

 

Our payment obligations in connection with a majority of these hedging transactions are secured by a first priority lien in the collateral securing the Partnership’s senior secured indebtedness that ranks equal in right of payment with liens granted in favor of its senior secured lenders. Some of our hedges are futures contracts executed through a broker that clears the hedges through an exchange. On a

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daily basis, our cash balance with the broker is used to offset the fair value of our open futures positions. The net of our cash on deposit and open futures positions is located within other current assets on our Consolidated Balance Sheets as a broker receivable.

The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net asset of $16.6 million as of September 30, 2016. The estimated fair value is net of an adjustment for credit risk based on the default probabilities by year as indicated by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented. Our futures contracts that are cleared through an exchange are settled daily and do not require any credit adjustment.

The following tables reflect amounts recorded in Other Comprehensive Income (“OCI”) and amounts reclassified from OCI to revenue and expense for the periods indicated:

 

 

Our consolidated earnings are also affected by the use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices.

 

 

The following table shows the deferred gains (losses) included in accumulated OCI, which will be reclassified into earnings through the end of 2019 based on valuations as of the balance sheet date:

 

 

 

See Note 13 – Fair Value Measurements for additional disclosures related to derivative instruments and hedging activities.

 

 

Note 13 — Fair Value Measurements

Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“financial instruments”). Derivative financial instruments and contingent consideration related to business acquisitions are reported at fair value in our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost in our Consolidated Balance Sheets. The following are additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments.

Fair Value of Derivative Financial Instruments

Our derivative instruments consist of financially settled commodity swaps, futures, option contracts and fixed-price forward commodity contracts with certain counterparties. We determine the fair value of our derivative contracts using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. We have consistently applied these valuation techniques in all periods presented and we believe we have obtained the most accurate information available for the types of derivative contracts we hold.

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The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The financial position of these derivatives at September 30, 2016, a net asset position of $16.6 million, reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of $27.7 million, ignoring an adjustment for counterparty credit risk. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of $61.4 million, ignoring an adjustment for counterparty credit risk.

Fair Value of Other Financial Instruments

Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. Long-term debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows:

We have a contingent consideration liability for APL’s previous acquisition of a gas gathering system and related assets, which is carried at fair value (see Note 4 – Business Acquisitions).

Fair Value Hierarchy

We categorize the inputs to the fair value measurements of financial assets and liabilities at each balance sheet reporting date using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value:

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The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included in our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments:

 

 

Additional Information Regarding Level 3 Fair Value Measurements Included in Our Consolidated Balance Sheets

We reported certain of our swaps and option contracts at fair value using Level 3 inputs due to such derivatives not having observable implied volatilities or market prices for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods.

The fair value of these swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For these derivatives, the primary input to the valuation model is the forward commodity basis curve, which is based on observable or public data sources and extrapolated when observable prices are not available.

As of September 30, 2016, we had 21 commodity swap and option contracts categorized as Level 3. The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives are (i) the forward natural gas liquids pricing curves, for which a significant portion of the derivative’s term is beyond available forward pricing and (ii) implied volatilities, which are unobservable as a result of inactive natural gas liquids options trading. The change in the fair value of Level 3 derivatives associated with a 10% change in the forward basis curve where prices are not observable is immaterial.

The fair value of the contingent consideration was determined using a probability-based model measuring the likelihood of meeting certain volumetric measures. These probability-based inputs are not observable; therefore, the entire valuation of the contingent consideration is categorized in Level 3.  Changes in the fair value of this liability are included in Other Income on the Consolidated Statements of Operations.

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The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy:

 

 

For the nine months ended September 30, 2016, we had no transfers of financial instruments out of Level 3 and into Level 2. Historically, transfers relate to long-term over-the-counter swaps for natural gas and NGL products with deliveries for which observable market prices were available.

 

 

Note 14 — Related Party Transactions - Targa

Relationship with Targa

We do not have any employees. Targa provides operational, general and administrative and other services to us associated with our existing assets and assets acquired from third parties. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing.

Our Partnership Agreement governs the reimbursement of costs incurred by Targa on behalf of us. Targa charges us for all the direct costs of the employees assigned to our operations, as well as all general and administrative support costs other than (1) costs attributable to Targa’s status as a separate reporting company and (2) costs of Targa providing management and support services to certain unaffiliated spun-off entities. We generally reimburse Targa monthly for cost allocations to the extent that Targa has made a cash outlay.

The following table summarizes transactions with Targa. Management believes these transactions are executed on terms that are fair and reasonable.

 

 

 

Note 15 - Contingencies

Legal Proceedings

Litigation related to TRC/TRP Merger

On December 16, 2015, two purported unitholders of TRP (the “State Court Plaintiffs”) filed a putative class action and derivative lawsuit challenging the TRC/TRP Merger against TRC, TRP (as a nominal defendant), TRP GP, the members of the board of TRP GP (the “TRP GP Board”) and Merger Sub (collectively, the “State Court Defendants”). This lawsuit is styled Leslie Blumberg et al. v. TRC Resources Corp., et al., Cause No. 2015-75481, in the 234^th Judicial District Court of Harris County, Texas (the “State Court Lawsuit”). The State Court Plaintiffs amended the State Court Lawsuit on July 26, 2016.

 

The State Court Plaintiffs allege several causes of action challenging the TRC/TRP Merger. Generally, the State Court Plaintiffs allege that (i) the members of the TRP GP Board breached express and/or implied duties under the Partnership Agreement and (ii) TRC, TRP GP, and Merger Sub aided and abetted in these alleged breaches of duties. The State Court Plaintiffs further allege, in general, that (a)

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the premium offered to TRP’s unitholders was inadequate, (b) the TRC/TRP Merger did not include a collar to protect TRP unitholders from decreases in TRC’s stock price, (c) the TRP GP Board agreed to contractual terms that allegedly may have dissuaded other potential acquirers from seeking to acquire TRP (including the “no-solicitation,” “matching rights,” and “termination fee” provisions), (d) the process leading up to the TRC/TRP Merger was unfair, (e) the TRP GP Board had conflicts of interest due to TRC’s control of TRP GP, (f) the TRP GP Conflicts Committee’s financial advisor was conflicted and conducted flawed analyses, and (g) the joint proxy statement/prospectus filed in connection with the TRC/TRP Merger (the “Proxy”) failed to disclose allegedly material information concerning, among other things, (i) the TRC and TRP projections included in the Proxy, and (ii) the analyses conducted by the TRP GP Conflicts Committee’s financial advisor in connection with the TRC/TRP Merger.

 

Based on these allegations, the State Court Plaintiffs seek damages and attorneys’ fees.  On February 26 and 29, 2016, the State Court Defendants filed general denials and asserted affirmative defenses. On August 26, 2016, the State Court Defendants filed Special Exceptions and a Motion for Summary Judgment seeking to have the State Court Lawsuit dismissed in its entirety with prejudice. The

Special Exceptions and Motion for Summary Judgment are pending before the Court.

The State Court Defendants cannot predict the outcome of this or any other lawsuits that might be filed subsequent to the date of the filing of this report, nor can the State Court Defendants predict the amount of time and expense that will be required to resolve such litigation. The State Court Defendants believe the State Court Lawsuit is without merit and intend to defend vigorously against this lawsuit and any other actions that challenge the TRC/TRP Merger. 

Environmental Proceedings

 

On June 18, 2015, the New Mexico Environment Department’s Air Quality Bureau issued a Notice of Violation to Targa Midstream Services LLC for alleged violations of air emissions regulations related to emissions events that occurred at the Monument Gas Plant between June 2014 and December 2014.  The Monument Gas Plant is owned and operated by Versado Gas Processors, L.L.C., which was a joint venture in which we owned a 63% interest and Targa Midstream Services LLC served as operator until October 31, 2016, when we acquired the remaining 37% membership interest from Chevron U.S.A Inc. The Partnership is in discussions with the New Mexico Environment Department to resolve the alleged violations. The Partnership anticipates that this matter could result in a monetary sanction in excess of $100,000 but less than $300,000.

We are also a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business.

 

 

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Note 16 — Supplemental Cash Flow Information

 

 

 

 

Note 17 — Segment Information

 

We operate in two primary segments (previously referred to as divisions): (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business).

Our reportable segments include operating segments that have been aggregated based on the nature of the products and services provided. Concurrent with the completion of the TRC/TRP Merger in the first quarter of 2016, management reevaluated our reportable segments and determined that our previously disclosed divisions are the appropriate level of aggregation for our reportable segments. The increase in activity within Field Gathering and Processing due to the Atlas mergers coupled with the decline in activity in our Gulf Coast region makes the disaggregation of Field Gathering and Processing and Coastal Gathering and Processing no longer warranted. Management also determined that further disaggregation of our Logistics and Marketing segment is no longer appropriate due to the integrated nature of the operations within our Downstream Business and its leadership by a consolidated executive management team. The Gathering and Processing division was previously disaggregated into two reportable segments—(a) Field Gathering and Processing and (b) Coastal Gathering and Processing. The Logistics and Marketing division (also referred to as the Downstream Business) was previously disaggregated into two reportable segments—(a) Logistics Assets and (b) Marketing and Distribution.

Our Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma and South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and Marketing segment includes all the activities necessary to convert mixed NGLs into NGL products and provides certain value added services such as storing, terminaling, distributing and marketing of NGLs, the storage and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our other businesses including

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services to LPG exporters. It also includes certain natural gas supply and marketing activities in support of our other operations, as well as transporting natural gas and NGLs.

Logistics and Marketing operations are generally connected to and supplied in part by our Gathering and Processing segments and are predominantly located in Mont Belvieu and Galena Park, Texas, Lake Charles, Louisiana and Tacoma, Washington.

Other contains the results (including any hedge ineffectiveness) of commodity derivative activities included in operating margin. and mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column.

Reportable segment information is shown in the following tables:

 

 

 

 

 

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The following table shows our consolidated revenues by product and service for the periods presented:

 

 

The following table shows a reconciliation of operating margin to net income (loss) for the periods presented:

 

 

 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in our Annual Report on Form 10-K for the year ended December 31, 2015 (“Annual Report”), as well as the unaudited consolidated financial statements and Notes hereto included in this Quarterly Report on Form 10-Q.

Overview

Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by TRC. Our common units were listed on the NYSE under the symbol “NGLS.” Our Preferred Units are listed on the NYSE under the symbol “NGLS PRA.”

Targa Resources GP LLC, our general partner, is a Delaware limited liability company formed by Targa in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly owned subsidiary of Targa.

On February 17, 2016, TRC completed the previously announced transactions contemplated by the Merger Agreement, by and among us, our general partner, TRC and Merger Sub pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the Merger Agreement, Merger Sub merged with and into TRP, with TRP continuing as the surviving entity and as a subsidiary of TRC. Following the closing of the TRC/TRP Merger on February 17, 2016, TRC owns all of our outstanding common units.

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Our Operations

 

We are a leading United States provider of midstream natural gas and NGL services, with a growing presence in crude oil gathering and petroleum terminaling. Our common units were listed on the NYSE under the symbol “NGLS” prior to TRC's acquisition on February 17, 2016 of all of our outstanding common units that it and its subsidiaries did not already own. Our 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) remain outstanding as preferred limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.”

We are engaged in the business of:

To provide these services, we operate in two primary segments (previously referred to as divisions): (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business).

Concurrent with the TRC/TRP Merger, management reevaluated our reportable segments and determined that our previously disclosed divisions are the appropriate level of disclosure. The Gathering and Processing division was previously disaggregated into two reportable segments—(a) Field Gathering and Processing and (b) Coastal Gathering and Processing. The Logistics and Marketing division (also referred to as the Downstream Business) was previously disaggregated into two reportable segments—(a) Logistics Assets and (b) Marketing and Distribution. The increase in activity within Field Gathering and Processing due to the Atlas mergers coupled with the decline in activity in our Gulf Coast region makes the disaggregation of Field Gathering and Processing and Coastal Gathering and Processing no longer warranted. Management also determined that further disaggregation of our Logistics and Marketing segment is no longer appropriate due to the integrated nature of the operations within our Downstream Business and its leadership by a consolidated executive management team.

Our Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma and South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and Marketing segment includes all the activities necessary to convert mixed NGLs into NGL products and provides certain value added services such as storing, terminaling, distributing and marketing of NGLs, the storage and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our other businesses including services to LPG exporters. It also includes certain natural gas supply and marketing activities in support of our other operations, as well as transporting natural gas and NGLs.

The Logistics and Marketing operations are generally connected to and supplied in part by our Gathering and Processing operations and are predominantly located in Mont Belvieu and Galena Park, Texas, Lake Charles, Louisiana and Tacoma, Washington.

Other contains the results (including any hedge ineffectiveness) of our commodity derivative activities which are included in operating margin.

 

Volatility of Commodity Prices

 

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development and production of new oil and natural gas reserves. Drilling and production activity generally decreases as crude oil and natural gas prices decrease below commercially acceptable levels. Prices of oil and natural gas have been volatile, and we expect this volatility to continue. Our operations are affected by the level of crude, natural gas and NGL prices, the relationship among these prices and related reduced activity levels from our customers. Beginning in the fourth quarter of 2014, oil and natural gas prices declined significantly primarily due to global supply and demand imbalances. Oil and natural gas prices continued to decline in 2015 and have remained depressed in 2016 as compared to 2014 levels.  

 

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2016 Developments

 

Logistics and Marketing Segment Expansion

 

Cedar Bayou Fractionator Train 5

 

In June 2016, we commissioned an additional fractionator, Train 5, at our 88%-owned Cedar Bayou Fractionator (“CBF”) in Mont Belvieu, Texas. This expansion added 100 MBbl/d of fractionation capacity at CBF, and is fully integrated with our existing Gulf Coast NGL storage, terminaling and delivery infrastructure, which includes an extensive network of connections to key petrochemical and industrial customers as well as our LPG export terminal at Galena Park on the Houston Ship Channel. The gross cost of Train 5 was approximately $328 million (our net cost was approximately $297 million).

 

Channelview Splitter

 

On December 27, 2015, we and Noble entered into the Splitter Agreement under which we will build and operate a 35,000 barrel per day crude and condensate splitter at our Channelview Terminal on the Houston Ship Channel (“Channelview Splitter”). The Channelview Splitter will have the capability to split approximately 35,000 barrels per day of crude and condensate into its various components, including naphtha, kerosene, gas oil, jet fuel, and liquefied petroleum gas and will provide segregated storage for the crude, condensate and components. The Channelview Splitter is expected to be completed by early 2018, and has an estimated total cost of approximately $140 million. As contemplated by the December 2014 Agreement, the Splitter Agreement completes and terminates the December 2014 Agreement, while retaining our economic benefits from that agreement. The first annual payment due under the Splitter Agreement was received in October 2016 and will be reflected as deferred revenue as a component of Other long-term liabilities on our Consolidated Balance Sheet.

 

Gathering and Processing Segment Expansion

 

Permian Basin Buffalo Plant

 

In April 2016, we commenced commercial operations of a new 200 MMcf/d cryogenic processing plant, known as the Buffalo Plant, in our WestTX system. This project also included the laying of new high and low pressure gathering lines in Martin and Andrews counties of Texas. Total growth capital expenditures for the Buffalo Plant were approximately $140 million (our net growth capital expenditures were approximately $102 million). The addition of the Buffalo Plant will enable us to meet increasing production from our joint venture partner in WestTX, Pioneer (the largest active driller in the Spraberry and Wolfberry Trends), and from other producers in the area.

 

Eagle Ford Shale Natural Gas Processing Joint Venture

 

In October 2015, we announced that we had entered into joint venture agreements with Sanchez Energy Corporation (“Sanchez”) to construct a new 200MMcf/d cryogenic natural gas processing plant in La Salle County, Texas (the “Raptor Plant”) and approximately 45 miles of associated pipelines. In July 2016, Sanchez sold its interest in the gathering joint venture to Sanchez Production L.P. ("SPP") and in October 2016 announced an agreement to sell its interest in the processing joint venture to SPP. We own a 50% interest in the plant and the approximately 45 miles of high pressure gathering pipelines that will connect Sanchez's Catarina gathering system to the plant. We hold a portion of the transportation capacity on the pipeline, and the gathering joint venture receives fees for transportation. We expect to invest approximately $125 million of growth capital expenditures related to the joint ventures.

 

The Raptor Plant will accommodate the growing production from Sanchez’s premier Eagle Ford Shale acreage position in Dimmit, La Salle and Webb Counties, Texas and from other third party producers. The plant and high pressure gathering lines are supported by long-term, firm, fee-based contracts and acreage dedications with Sanchez. We will manage construction and operations of the plant and high pressure gathering lines, and the plant is expected to begin operations in early 2017. Prior to the plant being placed in service, we benefit from Sanchez natural gas volumes that are processed at our Silver Oak facilities in Bee County, Texas.

 

Additional WestTX System Processing Capacity

 

In November 2016, we announced plans to restart the currently idled 45 MMcf/d Benedum cryogenic processing plant in our WestTX system.  The Benedum Plant was idled in September 2014 after the start-up of the 200 MMcf/d Edward Plant.  Also in November 2016, we announced plans to build a new 200 MMcf/d cryogenic processing plant in WestTX. The new plant is expected to be completed by the end of 2017. Also in November 2016, we announced that we were adding 20 MMcf/d of capacity at our Midkiff plant, increasing overall plant capacity from 60 MMcf/d to 80 MMcf/d.

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In addition to the major projects noted above, we have other growth capital expenditures in 2016 related to the continued build out of our gathering and processing infrastructure and logistics capabilities. On October 31, 2016, we acquired the remaining 37% membership interest in Versado Gas Processors, L.L.C. from Chevron U.S.A. Inc. In the current environment, we will continue to evaluate other potential projects based on return profile, capital requirements and strategic need and may choose to defer projects depending on expected activity levels.

Financing Activities

 

During the nine months ended September 30, 2016, we repurchased a portion of our outstanding senior notes on the open market, paying $534.3 million plus accrued interest to repurchase $559.2 million of the notes. The repurchases resulted in a $21.4 million net gain, which included the write-off of $3.5 million in related debt issuance costs.

 

We may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

 

During the nine months ended September 30, 2016, Targa made capital contributions to us of $1,191.0 million. Related to these capital contributions, we issued to Targa 58,621,036 common units, and Targa issued general partner units of 1,196,346 to maintain its 2% general partner interest. Proceeds from these contributions were used for general partnership purposes including repayment of indebtedness.

 

In October 2016, we issued $500.0 million of 5⅛% Senior Notes due February 2025 and $500.0 million of 5⅜% Senior Notes due February 2027 (collectively, the “2016 Senior Notes”), yielding net proceeds of approximately $496.2 million and $496.2 million, respectively. The net proceeds from the offering of the 2016 Senior Notes (the “October 2016 Offering”), along with borrowings under the TRP Revolver were used to fund concurrent tender offers for other series of senior notes.

 

Concurrently with the October 2016 offering, we commenced tender offers (the “Tender Offers”) to purchase for cash, subject to certain conditions, up to specified aggregate maximum purchase amounts of our 5% Senior Notes due January 2018 (the “5% Notes”), 6⅝% Senior Notes due October 2020 (the “6⅝% Notes”) and 6⅞% Senior Notes due February 2021 (the “6⅞% Notes” and together with the 5% Notes and 6⅝% Notes, the “Tender Notes”). The total consideration for each series of Tender Notes included a premium for each $1,000 principal amount of notes that was tendered as of the early tender date of October 5, 2016. The Tender Offers were fully subscribed and we accepted for purchase all Tender Notes that were validly tendered as of the early tender date.

 

The results of the Tender Offers, which closed in October 2016, were:

 

Subsequent to the closing of the Tender Offers in October 2016, we issued notices of full redemption to the trustees and noteholders of the 6⅝% Notes and the 6⅞% Notes for the note balances remaining after the Tender Offers. In addition, we issued notice of full redemption to the trustees of the 6⅝% APL Notes due October 2020. The redemption price for the 6⅝% Notes and the 6⅝% APL Notes due October 2020 was 103.313% of the principal amount, while the redemption price for the 6⅞% Notes was 103.438% of the principal amount. The aggregate principal amount outstanding of all three series of notes totaling $146.2 million will be redeemed on November 15, 2016 for a total payment of $151.1 million, excluding accrued interest.

 

In October 2016, we entered into the Second Amendment and Restatement Agreement (the “Restatement”) to effectuate the Third Amended and Restated Credit Agreement (the “TRP Credit Agreement”). The TRP Credit Agreement amended and restated the TRP Revolver to extend the maturity date from October 2017 to October 2020. The available commitments under the TRP Revolver of $1.6 billion remained unchanged while our ability to request additional commitments increased from up to $300.0 million to up to $500.0 million. The TRP Revolver continues to bear interest costs that are dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA, and the covenants also remained substantially the same. The TRP Credit Agreement designates TPL and certain of its subsidiaries as “Restricted Subsidiaries” and provides for certain changes to occur upon our receiving an investment grade credit rating from Moody’s or S&P including the release of the security interests in all collateral at our request.

 

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Subsequent to entering into the TRP Credit Agreement, we executed supplemental indentures relating to all of our outstanding series of Senior Notes to designate the TPL subsidiaries as Restricted Subsidiaries under the TRP Credit Agreement as guarantors of the Senior Notes.

 

 

Recent Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The update also creates a new Subtopic 340-40, Other Assets and Deferred Costs – Contracts with Customers, which provides guidance for the incremental costs of obtaining a contract with a customer and those costs incurred in fulfilling a contract with a customer that are not in the scope of another topic. The new revenue standard requires that entities should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entities expect to be entitled in exchange for those goods or services. To achieve that core principle, the standard requires a five step process of identifying the contracts with customers, identifying the performance obligations in the contracts, determining the transaction price, allocating the transaction price to the performance obligations, and recognizing revenue when, or as, the performance obligations are satisfied. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

With the issuance in August 2015 of ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, the revenue recognition standard is effective for the annual period beginning after December 15, 2017, and for annual and interim periods thereafter. Earlier adoption is permitted for annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We must retroactively apply the new revenue recognition standard to transactions in all prior periods presented, but will have a choice between either (1) restating each prior period presented or (2) presenting a cumulative effect adjustment in the period the amendment is adopted.

In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations. The amendments in this update improve the operability and understandability of the implementation guidance on principal versus agent considerations, including clarifying that an entity should determine whether it is a principal or an agent for each specified good or service promised to a customer. These amendments are effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2017, with early adoption permitted.

In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. These amendments clarify the guidance on identification of performance obligations and licensing. The amendments include that entities do not have to decide if goods and services are performance obligations if they are considered immaterial in the context of a contract. Entities are also permitted to account for the shipping and handling that takes place after the customer has gained control of the goods as actions to fulfill the contract rather than separate services. In order to identify a performance obligation in a customer contract, an entity has to determine whether the goods or services are distinct, and ASU No. 2016-10 clarifies how the determination can be made.

In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients. These amendments address certain implementation issues related to assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition, and also provide additional practical expedients.

We expect to adopt these updates in their entirety on January 1, 2018, and are continuing to evaluate the impact on our revenue recognition practices.

Consolidation

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The amendments are intended to simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities and modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities. The amendments were effective for us in 2016 with no impact on our consolidated financial statements.

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Presentation of Debt Issuance Costs

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The amendments in this update require that debt issuance costs related to a recognized debt liability (other than line-of-credit or other revolving credit facilities) be presented in the Consolidated Balance Sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This update dealt solely with financial statement display matters; recognition and measurement of debt issuance costs were unaffected. We adopted the amendments on January 1, 2016 and have reclassified unamortized debt issuance costs of $38.3 million on our Consolidated Balance Sheet as of December 31, 2015 from Other long-term assets to Long-term debt to conform to current year presentation. Our Consolidated Balance Sheet as of September 30, 2016 has $29.4 million in unamortized debt issuance costs classified in Long-term debt.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We expect to adopt the amendments in the first quarter of 2019 and are currently evaluating the impacts of the amendments to our consolidated financial statements and accounting practices for leases.

Share-Based Compensation

In March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The amendments in this update provides, among other things, that (1) all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit in the income statement with the tax effects of exercised or vested awards treated as discrete items in the reporting period in which they occur and recognition of excess tax benefits regardless of whether the benefit reduces taxes payable in the current period; (2) excess tax benefits should be classified along with other income tax cash flows as an operating activity; (3) an entity can make an entity-wide accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur; (4) the threshold to qualify for equity classification permits withholding up to the maximum statutory tax rates in the applicable jurisdictions; and (5) cash paid by an employer when directly withholding shares for tax-withholding purposes should be classified as a financing activity on the statement of cash flows. We adopted the applicable amendments in the second quarter of 2016; however there was no impact to our consolidated financial statements.

Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. These amendments change the measurement of credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The amendments in this update affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. The amendments replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. We expect to adopt this guidance on January 1, 2019, and are continuing to evaluate the impact on our measurement of credit losses.

Cash Flow Classification

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). These amendments clarify how entities should classify certain cash receipts and cash payments on the statement of cash flows related to the following transactions: (1) debt prepayment or extinguishment costs; (2) settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing; (3) contingent consideration payments made after a business combination; (4) proceeds from the settlement of insurance claims; (5) proceeds from the settlement of corporate-owned life insurance; (6) distributions received from equity method investees; and (7) beneficial interests in securitization transactions. Additionally, the update clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the effect of the amendments on our consolidated financial statements and related disclosures.

 

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Recognition of Intra-Entity Transfers of Assets Other than Inventory

In October 2016, the FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory. The amendments in this update are intended to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party which is an exception to the principle of comprehensive recognition of current and deferred income taxes in GAAP. This update eliminates the exception by requiring entities to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the effect of the amendments on our consolidated financial statements and related disclosures.

 

 

How We Evaluate Our Operations

The profitability of our business segments is a function of the difference between: (i) the revenues we receive from our operations, including fee-based revenues from services and revenues from the natural gas, NGLs, crude oil and condensate we sell, and (ii) the costs associated with conducting our operations, including the costs of wellhead natural gas, crude oil and mixed NGLs that we purchase as well as operating, general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for crude oil, natural gas and NGLs and the volumes of crude oil, natural gas and NGL throughput on our systems are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services, utilization of our assets and changes in our customer mix.

Our profitability is also impacted by fee-based revenues. Our growth strategy, based on expansion of existing facilities as well as third-party acquisitions of businesses and assets, has increased the percentage of our revenues that are fee-based. Fixed fees for services such as fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities.

Management uses a variety of financial measures and operational measurements to analyze our performance. These include: (1) throughput volumes, facility efficiencies and fuel consumption, (2) operating expenses, (3) capital expenditures and (4) the following non-GAAP measures: gross margin, operating margin, and adjusted EBITDA.

Throughput Volumes, Facility Efficiencies and Fuel Consumption

Our profitability is impacted by our ability to add new sources of natural gas supply and crude oil supply to offset the natural decline of existing volumes from oil and natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing crude oil and natural gas supplies currently gathered by third-parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, typically connected by third-party transportation, to our Downstream Business fractionation facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL supply from third-party facilities.

In addition, we seek to increase operating margin by limiting volume losses, reducing fuel consumption and by increasing efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes received at the wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. We also monitor the volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants and Downstream Business facilities to determine customer settlements for sales and volume related fees for service and helps us increase efficiency and reduce fuel consumption.

As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of our facilities. Similar tracking is performed for our crude oil gathering and logistics assets. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis and safety programs.

Operating Expenses

Operating expenses are costs associated with the operation of specific assets. Labor, contract services, repair and maintenance, utilities and ad valorem taxes comprise the most significant portion of our operating expenses. These expenses, other than fuel and power,

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generally remain relatively stable and independent of the volumes through our systems, but fluctuate depending on the scope of the activities performed during a specific period.

Capital Expenditures

Capital projects associated with growth and maintenance projects are closely monitored. Return on investment is analyzed before a capital project is approved, spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approval.

Gross Margin

We define gross margin as revenues less product purchases. It is impacted by volumes and commodity prices as well as by our contract mix and commodity hedging program.

Gathering and Processing segment gross margin consists primarily of  revenues from the sale of natural gas, condensate, crude oil and NGLs and fee revenues related to natural gas and crude oil gathering and services, less producer payments and other natural gas and crude oil purchases.

Logistics and Marketing segment gross margin consists primarily of

The gross margin impacts of cash flow hedge settlements are reported in Other.

Operating Margin

We define operating margin as gross margin less operating expenses. Operating margin is an important performance measure of the core profitability of our operations. 

Management reviews business segment gross margin and operating margin monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that management uses in evaluating our operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures by management and by external users of our financial statements, including investors and commercial banks, to assess:

Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is net income. Gross margin and operating margin are not alternatives to GAAP net income and have important limitations as analytical tools. Investors should not consider gross margin and operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies in our industry, our definitions of gross margin and operating margin may not be comparable with similarly titled measures of other companies, thereby diminishing their utility.

Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

 

Adjusted EBITDA

 

We define Adjusted EBITDA as net income attributable to TRP before: interest; income taxes; depreciation and amortization; impairment of goodwill; gains or losses on debt repurchases, redemptions, amendments, exchanges and early debt extinguishments and asset disposals; risk management activities related to derivative instruments, including the cash impact of hedges acquired in the APL merger; non-cash compensation on TRP equity grants; transaction costs related to business acquisitions; earnings/losses from

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unconsolidated affiliates net of distributions, distributions from preferred interests, change in contingent consideration and the noncontrolling interest portion of depreciation and amortization expenses. Adjusted EBITDA is used as a supplemental financial measure by us and by external users of our financial statements such as investors, commercial banks and others. The economic substance behind our use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our investors.

 

Adjusted EBITDA is a non-GAAP financial measure. The GAAP measure most directly comparable to Adjusted EBITDA is net income (loss) attributable to TRP. Adjusted EBITDA should not be considered as an alternative to GAAP net income. Adjusted EBITDA has important limitations as an analytical tool. Investors should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

 

Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

 

The following tables reconcile the non-GAAP financial measures used by management to the most directly comparable GAAP measures for the periods indicated, with 2015 amounts presented for comparative purposes.

 

 

 

 

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Consolidated Results of Operations

The following table and discussion is a summary of our consolidated results of operations:

 

 

NM      Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.

Three Months Ended September 30, 2016 Compared to Three Months Ended September 30, 2015

The increase in revenues was primarily due to higher NGL prices ($104.0 million) and higher natural gas sales volumes ($14.3 million), partially offset by decreased fee-based and other revenues ($57.1 million) from lower fractionation and export fees, and lower crude and natural gas prices ($11.3 million).

Higher NGL prices brought a commensurate increase in product purchases.

 

The lower operating margin and gross margin in 2016 was primarily attributable to decreased segment results for Logistics and Marketing. Improved margins in our Gathering and Processing segment were essentially offset by lower commodity derivative

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settlement revenues in Other. Operating expenses were relatively flat in 2016 as compared to 2015. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.

The increase in depreciation and amortization expenses primarily reflects the impact of growth investments from system expansions.

General and administrative expenses were relatively flat in 2016 as compared to 2015.

Other operating expenses in 2016 include the loss on decommissioning of two storage wells at our Hattiesburg facility and an acid gas injection well at our Versado facility.

The decrease in net interest expense in 2016 is primarily due to $4.2 million of non-cash interest income resulting from the change in estimated redemption value of the mandatorily redeemable preferred interests for the three months ended September 30, 2016.

The decrease in net income attributable to noncontrolling interests was primarily attributable to overall lower earnings for the third quarter of 2016 at our joint ventures.

Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015

The decrease in revenues was primarily due to lower commodity prices ($521.6 million), partially offset by the favorable impact of inclusion of two additional months of operations of TPL during 2016 ($270.1 million). Additionally, fee-based and other revenues decreased due to lower fractionation and export fees ($97.9 million), partially offset by the impact of an additional two months of TPL’s fee revenue in 2016 ($40.9 million).

Lower commodity prices brought a commensurate reduction in product purchases, partially offset by the inclusion of two additional months of operations from TPL in 2016 ($137.5 million).

 

The lower operating and gross margin in 2016 reflects decreased segment margin results for Logistics and Marketing, partially offset by increased Gathering and Processing margins. Operating expenses were relatively flat compared to 2015 due to the inclusion of TPL’s operations for an additional two months in 2016, offset by a continued focused cost reduction effort throughout our operating areas. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.

The increase in depreciation and amortization expenses is primarily due to an additional two months of TPL operations in 2016, growth investments from other system expansions including CBF Train 5, the Buffalo Plant, compressor stations and pipelines, and higher amortization of the Badlands intangible assets.

General and administrative expenses, which include TPL operations for an additional two months in 2016, reflect operational synergies, including integrating TPL into Targa’s insurance program.

During 2016, we recognized an additional impairment of goodwill of $24.0 million to finalize the $290.0 million provisional impairment recorded during the fourth quarter of 2015.

Other operating expenses in 2016 include the loss on decommissioning of two storage wells at our Hattiesburg facility and an acid gas injection well at our Versado facility.

Net interest expense was relatively flat, resulting from higher interest expense from an increase in borrowings primarily from the September 2015 issuance of $600.0 million of 6¾% Senior Notes, offset by $18.8 million of non-cash interest income from a reduction in the estimated redemption value of the mandatorily redeemable preferred interests during 2016 and lower interest expense resulting from $534.3 million of open market debt repurchases during 2016.

The decrease in equity earnings (loss) is due to lower operating results from GCF and the inclusion of an additional two months of equity losses from the T2 Joint Ventures in 2016.

During the nine months ended September 30, 2016, we repurchased $534.3 million of debt in open market purchases, which generated a net gain of $21.4 million.

Other expense in 2015 was primarily attributable to non-recurring transaction costs related to the APL merger.

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The decrease in net income attributable to noncontrolling interests was primarily attributable to lower earnings in 2016 at our joint ventures.

Results of Operations—By Reportable Segment

Our operating margins by reportable segment are:

 

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Gathering and Processing Segment

 

 

 

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Three Months Ended September 30, 2016 Compared to Three Months Ended September 30, 2015

The increase in gross margin was primarily due to higher NGL prices offset by lower inlet volumes and lower condensate prices. Plant inlet volumes increased in the Permian region driven by WestTX and SAOU. The volume increase at SouthTX partially offset an overall inlet volume decrease in the Central region. Despite overall lower inlet volumes, NGL production increased primarily due to additional ethane recovery at SouthOK. Natural gas sales volumes decreased due to lower inlet volumes. Badlands natural gas volumes increased due to system expansions for specific gas and oil producers while crude oil volumes decreased due to reduced producer activity by crude oil only producers.

Operating expenses decreased primarily due to a continued focus on cost reductions, which more than offset increased expenses associated with the commencement of commercial operations in April 2016 at the Buffalo plant in WestTX, other system expansions and an operational issue at Versado.

Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015

The increase in gross margin was primarily due to the inclusion of the TPL volumes for three quarters of 2016 partially offset by lower commodity prices and lower inlet volumes on our other systems. The plant inlet volume increases in the Permian region attributable to SAOU were offset by reduced producer activity and operational issues at Sand Hills and Versado and in the Central region by reduced producer activity and volumes in North Texas. Badlands crude oil and natural gas volumes increased due to plant and system expansions. Coastal plant inlet volumes decreased due to current market conditions and the decline of off-system volumes partially offset by additional higher GPM volumes.

Excluding the impact of including operating expenses for TPL for an additional two months in 2016 and system expansions, operating expenses for most areas were significantly lower due to a continued focused cost reduction effort.

Gross Operating Statistics Compared to Actual Reported

The table below provides a reconciliation between gross operating statistics and the actual reported operating statistics for the Gathering and Processing segment:

 

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Logistics and Marketing Segment

 

Three Months Ended September 30, 2016 Compared to Three Months Ended September 30, 2015

 

Logistics and Marketing gross margin decreased primarily due to lower LPG export margin, the realization in 2015 of contract renegotiation fees related to our crude and condensate splitter project, and various other items, partially offset by increased fractionation margin.  LPG export margin decreased due to lower fees and volumes, partially offset by cancellation fees.  Fractionation margin increased primarily due to higher system product gains, partially offset by a decrease in supply volume.

 

Operating expenses increased due to higher taxes associated with the start-up of CBF Train 5, partially offset by lower maintenance expense resulting primarily from fewer required well workovers and pipeline integrity tests in the third quarter 2016 compared to the same period last year, with continued focused reductions in nonessential maintenance projects also contributing.

Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015

 

Logistics and Marketing gross margin decreased due to lower LPG export margin, the realization in 2015 of contract renegotiation fees related to our crude and condensate splitter project, lower fractionation margin and lower terminaling and storage throughput.  LPG export margin decreased due to lower fees and volumes, partially offset by cancellation fees.  Fractionation margin decreased due to lower volumes and system product gains, and was partially impacted by the variable effects of fuel and power which are largely reflected in lower operating expenses (see footnote (2) above).

 

Operating expenses decreased primarily due to lower fuel and power expense, and lower maintenance expense resulting from continued focused cost reductions in nonessential maintenance projects. These decreases were partially offset by higher taxes associated with the start-up of CBF Train 5.

Other

 

 

Other contains the results (including any hedge ineffectiveness) of commodity derivative activities included in operating margin and mark-to-market gain/losses related to derivative contracts that were not designated as cash flow hedges. Eliminations of inter-segment transactions are reflected in the corporate and eliminations column. The primary purpose of our commodity risk management activities is to mitigate a portion of the impact of commodity prices on our operating cash flow. We have hedged the commodity price

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associated with a portion of our expected (i) natural gas equity volumes and (ii) NGL and condensate equity volumes in our Gathering and Processing Operations that result from percent of proceeds or liquid processing arrangements by entering into derivative instruments. Because we are essentially forward-selling a portion of our plant equity volumes, these hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices.

 

The following table provides a breakdown of the change in Other operating margin:

 

 

 

As part of the Atlas mergers, outstanding APL derivative contracts with a fair value of $102.1 million as of the acquisition date were novated to us and included in the acquisition date fair value of assets acquired. Derivative settlements of $5.8 million and $20.9 million related to these novated contracts were received during the three and nine months ended September 30, 2016 and were reflected as a reduction of the acquisition date fair value of the APL derivative assets acquired with no effect on results of operations.

 

 

Liquidity and Capital Resources

Our ability to finance our operations, including funding capital expenditures and acquisitions, meeting our indebtedness obligations, refinancing our indebtedness and meeting our collateral requirements, will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control. These include weather, commodity prices and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.

Our main sources of liquidity and capital resources are internally generated cash flows from operations, contributions from TRC that are funded through TRC’s access to debt and equity markets, borrowings under our senior secured revolving credit facility (“TRP Revolver”), borrowings under the accounts receivable securitization facility (“Securitization Facility”), and access to debt markets. For companies involved in hydrocarbon production, transportation and other oil and gas related services, the capital markets have experienced and may continue to experience volatility. Our exposure to adverse credit conditions includes our credit facility, cash investments, hedging abilities, customer performance risks and counterparty performance risks.

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Our liquidity as of October 17, 2016 , which reflects the TRP Credit Agreement, was:

 

 

Other potential capital resources associated with our existing arrangements include:

A portion of our capital resources may be allocated to letters of credit to satisfy certain counterparty credit requirements. These letters of credit reflect our non-investment grade status, as assigned to us by Moody’s and S&P. They also reflect certain counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors.

 

Issuance of Senior Unsecured Notes and Concurrent Senior Notes Tender Offers

 

In October 2016, we issued $500.0 million of 5⅛% Senior Notes due February 2025 and $500.0 million of 5⅜% Senior Notes due February 2027, yielding net proceeds of approximately $496.2 million and $496.2 million, respectively. The net proceeds from the October 2016 Offering along with borrowings under the TRP Revolver were used to fund concurrent tender offers for certain other series of senior notes.

 

Concurrently with the October 2016 Offering, we commenced the Tender Offers to purchase for cash, subject to certain conditions, up to specified aggregate maximum purchase amounts of the Tender Notes. The total consideration for each series of Tender Notes included a premium for each $1,000 principal amount of notes that was tendered as of the early tender date of October 5, 2016. The Tender Offers were fully subscribed and we accepted for purchase all Tender Notes that were validly tendered as of the early tender date, totaling $1,138.3 million of principal, as described in 2016 Developments above.

 

Note Redemptions

 

Subsequent to the closing of the Tender Offers in October 2016, we issued notices of full redemption to the trustees and noteholders of the 6⅝% Notes and the 6⅞% Notes for the note balances remaining after the Tender Offers. In addition, we issued notice of full redemption to the trustees of the 6⅝% APL Notes due October 2020. The redemption price for the 6⅝% Notes and the 6⅝% APL Notes due October 2020 was 103.313% of the principal amount, while the redemption price for the 6⅞% Notes was 103.438% of the principal amount. The aggregate principal amount outstanding of all three series of notes totaling $146.2 million will be redeemed on November 15, 2016 for a total redemption payment of $151.1 million, plus accrued interest.

 

TRP Revolver Amendment

 

In October 2016, we entered into the Restatement to effectuate the TRP Credit Agreement. The TRP Credit Agreement amended and restated the TRP Revolver to extend the maturity date from October 2017 to October 2020. The available commitments under the TRP Revolver of $1.6 billion remained unchanged while our ability to request additional commitments increased from up to $300.0 million to up to $500.0 million. The TRP Revolver continues to bear interest costs that are dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA, and the covenants also remained substantially the same. The TRP Credit Agreement designates TPL and certain of its subsidiaries as “Restricted Subsidiaries” and provides for certain changes to occur upon our receiving an investment grade credit rating from Moody’s or S&P, including the release of the security interests in all collateral at our request.

 

Subsequent to entering into the TRP Credit Agreement, we executed supplemental indentures relating to all of our outstanding series of Senior Notes to designate the TPL subsidiaries as Restricted Subsidiaries under the TRP Credit Agreement as guarantors of the Senior Notes.

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Working Capital

Working capital is the amount by which current assets exceed current liabilities. On a consolidated basis, at the end of any given month, accounts receivable and payable tied to commodity sales and purchases are relatively balanced, with receivables from NGL customers being offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported total working capital are: (1) our cash position; (2) liquids inventory levels and valuation, which we closely manage; (3) changes in the fair value of the current portion of derivative contracts; and (4) major structural changes in our asset base or business operations, such as acquisitions or divestitures and certain organic growth projects.

Our working capital, exclusive of current debt obligations, decreased $57.0 million.  The majority of this decrease was due to a lower net risk management working capital position due to changes in the forward prices of commodities.  The increase of $5.7 million in current debt obligations was due to increased borrowings under our AR Securitization facility resulting from higher available receivables.

Based on our anticipated levels of operations and absent any disruptive events, we believe that internally generated cash flow, contributions from TRC, borrowings available under the TRP Revolver and the Securitization Facility and proceeds from debt offerings should provide sufficient resources to finance our operations, capital expenditures, long-term debt obligations, collateral requirements and cash distributions to Targa for at least the next twelve months.

Cash Flow

Cash Flows from Operating Activities

The Consolidated Statements of Cash Flows included in our historical consolidated financial statements employs the traditional indirect method of presenting cash flows from operating activities. Under the indirect method, net cash provided by operating activities is derived by adjusting our net income for non-cash items related to operating activities. An alternative GAAP presentation employs the direct method in which the actual cash receipts and outlays comprising cash flow are presented.

The following table displays our operating cash flows using the direct method as a supplement to the presentation in our consolidated financial statements:

 

 

Lower commodity prices were the primary contributor to decreased cash collections and payments for product purchases in 2016 compared to 2015. Cash received from derivatives was lower primarily due to lower commodity price spreads in 2016 compared to 2015. Interest payments were higher in 2016, primarily due to the timing of interest payments related to the new borrowings in 2015. Cash payments for general and administrative expenses were lower primarily due to lower bonus payout and lower insurance premium payments. Other cash payments in 2016 were lower, mainly due to transaction expenses associated with the APL merger in 2015.

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Cash Flows from Investing Activities

 

 

The decrease in net cash used in investing activities for the nine months ended September 30, 2016, compared to the nine months ended September 30, 2015, was primarily due to the $828.7 million outlay for the cash portion of the Atlas mergers in 2015. Growth and maintenance capital expenditures decreased $200.3 million for the nine months ended September 30, 2016 as compared to the nine months ended September 30, 2015.

Cash Flows from Financing Activities

 

 

Net cash provided by (used in) financing activities decreased in the nine months ended September 30, 2016 as compared to the nine months ended September 30, 2015. During the nine months ended September 30, 2016, we reduced our debt exposure by repurchasing $534.3 million of our senior notes in the open market along with other net debt repayments of $274.3 million; whereas we incurred net borrowings of $918.9 million during the nine months ended September 30, 2015 primarily associated with the Atlas mergers. We had no public offerings of common units in the nine months ended September 30, 2016 as a result of the TRC/TRP merger, after which our common units were no longer publicly traded. In comparison, we received $318.6 million of proceeds from the sale of common units in the nine months ended September 30, 2015. Distributions paid to common unitholders increased by $10.9 million for the nine months ended September 30, 2016 as compared to the nine months ended September 30, 2015.

We received total capital contributions of $1,191.0 million from Targa for the nine months ended September 30, 2016, as compared to $60.1 million for the nine months ended September 30, 2015. Proceeds from these contributions were used for net debt repayments and redemptions of senior notes and other general partnership purposes.

 

 

Distributions to our Unitholders

We distribute all available cash from our operating surplus. As a result, we expect that we will rely upon external financing sources, including contributions from TRC and debt issuances, to fund our acquisition and expansion capital expenditures. See Note 9 – Debt Obligations and Note 11 – Partnership Units and Related Matters of the “Consolidated Financial Statements” included in this Quarterly Report.

In accordance with the Partnership Agreement, the Partnership must distribute all of its available cash, as defined in the Partnership Agreement, and as determined by the general partner, to Preferred Unitholders monthly and to common unitholders of record within 45 days after the end of each quarter. As a result of the TRC/TRP Merger, TRC is entitled to receive all available distributions from the Partnership after payment of preferred distributions each quarter. The following details the distributions declared or paid by the Partnership, net of the IDR Giveback, during 2016:

 

Distributions on the Partnership’s outstanding Series A Preferred Units are declared and paid monthly. For the nine months ended September 30, 2016, $8.4 million of distributions were paid. We have accrued distributions to Series A Preferred Unitholders of $0.9 million for September 30, 2016, which were paid subsequently on October 17, 2016. On October 17, 2016, the board of directors of our general partner declared a monthly cash distribution of $0.1875 per Series A Preferred Unit for October 2016. This distribution will be paid on November 15, 2016.

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Capital Requirements

Our capital requirements relate to capital expenditures, which are classified as expansion expenditures, which include business acquisitions, or maintenance expenditures. Expansion capital expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, reduce costs or enhance revenues, and fund acquisitions of businesses or assets. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets, including the replacement of system components and equipment, which are worn, obsolete or completing their useful life and expenditures to remain in compliance with environmental laws and regulations.

 

We currently estimate that we will invest approximately $525 million in net growth capital expenditures for announced projects in 2016. Given our objective of growth through expansions of existing assets, other internal growth projects, and acquisitions, we anticipate that over time that we will invest significant amounts of capital to grow and acquire assets. Future expansion capital expenditures may vary significantly based on investment opportunities. Our expansion capital expenditures decreased for the nine months ended September 30, 2016 as compared to the nine months ended September 30, 2015, primarily due to reduced Badlands spending activity and CBF Train 5 construction costs in 2016. Although CBF Train 5 started up in the second quarter of 2016, only slightly more than 20% of the construction costs were incurred in 2016. Our maintenance capital expenditures decreased for the nine months ended September 30, 2016 as compared to the nine months ended September 30, 2015, primarily due to fewer well connects and lengthened maintenance cycle times resulting from decreases in producer activity, as well as a higher percentage of environmental repairs incurred in the first nine months of 2015 versus 2016.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are set forth in Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report. There were no significant updates or revisions to these policies during the nine months ended September 30, 2016. We are supplementing our disclosures to provide additional explanations of estimates and assumptions used in accounting for business acquisitions.

 

Business Acquisitions

 

For business acquisitions, we generally recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the acquisition date. Determining fair value requires management’s judgment and involves the use of significant estimates and assumptions with respect to projections of future production volumes, pricing and cash flows, benchmark analysis of comparable public companies, discount rates, expectations regarding customer contracts and relationships, and other management estimates. The judgments made in the determination of the estimated fair value assigned to the assets acquired, the liabilities assumed and any noncontrolling interest in the investee, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition. See Note 4 - Business Acquisitions to our consolidated financial statements.

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Off-Balance Sheet Arrangements

As of September 30, 2016, there were $33.9 million in surety bonds outstanding related to various performance obligations. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and (ii) counterparty support. Obligations under these surety bonds are not normally called, as we typically comply with the underlying performance requirement.

Contractual Obligations

As of September 30, 2016, there have been no significant changes in the contractual obligations as presented in our 2015 Form 10-K, except as noted for debt repurchases which are disclosed in Note 9 – Debt Obligations in our Consolidated Financial Statements included in this Quarterly Report.

 

The following table summarizes payment obligations for our Senior Unsecured Notes as of September 30, 2016, after giving effect to debt repurchases during the nine months ended September 30, 2016, but does not include the impact of debt activity occurring after September 30, 2016 disclosed in this Quarterly Report:

 

 

 

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Commodity Price Risk

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil and changes in interest rates.

A significant portion of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the natural gas and/or NGLs or equity volumes as payment for services. The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged.

The primary purpose of the commodity risk management activities is to hedge some of the exposure to commodity price risk and reduce fluctuations in our operating cash flow due to fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of September 30, 2016, we have hedged the commodity price associated with a portion of our expected (i) natural gas equity volumes in our Gathering and Processing operations and (ii) NGL and condensate equity volumes in our Gathering and Processing operations that result from our percent-of-proceeds processing arrangements by entering into derivative instruments. We hedge a higher percentage of our expected equity volumes in the current year compared to future years, for which we hedge incrementally lower percentages of expected equity volumes. With swaps, we typically receive an agreed fixed price for a specified notional quantity of natural gas or NGLs and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We may buy calls in connection with swap positions to create a price floor with upside. We intend to continue to manage our exposure to commodity prices in the future by

57

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entering into derivative transactions using swaps, collars, purchased puts (or floors) or other derivative instruments as market conditions permit.

When entering into new hedges, we intend to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. The NGL hedges cover specific NGL products based upon the expected equity NGL composition. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. The natural gas and NGL hedges’ fair values are based on published index prices for delivery at various locations and we seek to closely approximate the actual natural gas and NGL delivery points. A portion of our condensate sales are hedged using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude.

A majority of these commodity price hedging transactions are typically documented pursuant to a standard International Swap Dealers Association form with customized credit and legal terms. The principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. Our payment obligations in connection with substantially all of these hedging transactions and any additional credit exposure due to a rise in natural gas and NGL prices relative to the fixed prices set forth in the hedges are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. Absent federal regulations resulting from the Dodd-Frank Act, and as long as this first priority lien is in effect, we expect to have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time, even if a counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness. A purchased put (or floor) transaction does not expose our counterparties to credit risk, as we have no obligation to make future payments beyond the premium paid to enter into the transaction; however, we are exposed to the risk of default by the counterparty, which is the risk that the counterparty will not honor its obligation under the put transaction.

We also enter into commodity price hedging transactions using futures contracts on futures exchanges. Exchange traded futures are subject to exchange margin requirements, so we may have to increase our cash deposit due to a rise in natural gas and NGL prices.  Unlike bilateral hedges, we are not subject to counterparty credit risks when using futures.

For all periods presented, we have entered into hedging arrangements for a portion of our forecasted equity volumes. During the three months ended September 30, 2016 and 2015, our operating revenues increased (decreased) by net hedge adjustments on commodity derivative contracts of $11.2 million and $21.8 million. During the nine months ended September 30, 2016 and 2015, our operating revenues increased (decreased) by net hedge adjustments on commodity derivative contracts of $56.9 million and $60.7 million.

58

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As of September 30, 2016, we had the following derivative instruments designated as hedging instruments that will settle during the years ending below:

Natural GAS

 

59

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60

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NGLs

 

61

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62

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CONDENSATE

 

 

As of September 30, 2016, we had the following derivative instruments that are not designated as hedges and are marked-to-market:

NATURAL GAS

 

 

These contracts may expose us to the risk of financial loss in certain circumstances. Generally, our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which they have been hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges (other than with respect to purchased calls). For derivative instruments not designated as cash flow hedges, these contracts are marked-to-market and recorded in revenues.

We account for the fair value of our financial assets and liabilities using a three-tier fair value hierarchy, which prioritizes the significant inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. We determine the value of our derivative contracts utilizing a discounted cash flow model for swaps and a standard option-pricing model for options based on inputs that are readily available in public markets. For the contracts that have inputs from quoted prices, the classification of these instruments is Level 2 within the fair value hierarchy. For those contracts which we are unable to obtain quoted prices for at least 90% of the full term of the commodity swap and options, the valuations are classified as Level 3 within the fair value hierarchy. See Note 13 - Fair Value Measurements in this Quarterly Report for more information regarding classifications within the fair value hierarchy.

Interest Rate Risk

We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under the TRP Revolver and the Securitization Facility. As of September 30, 2016, we do not have any interest rate hedges. However, we may in the future enter into interest rate hedges intended to mitigate the impact of changes in interest rates on cash flows. To the extent that interest rates increase, interest expense for the TRP Revolver and the Securitization Facility will also increase. As of September 30, 2016, we had $225.0 million in outstanding variable rate borrowings under the TRP Revolver and the Securitization Facility. A hypothetical change of 100 basis points in the interest rate of our variable rate debt would impact our annual interest expense by $2.3 million.

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Counterparty Credit Risk

We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. The credit exposure related to commodity derivative instruments is represented by the fair value of the asset position (i.e. the fair value of expected future receipts) at the reporting date. Our futures contracts have limited credit risk since they are cleared through an exchange and are settled daily. Should the creditworthiness of one or more of the counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted. We have master netting provisions in the International Swap Dealers Association agreements with all of our derivative counterparties. These netting provisions allow us to net settle asset and liability positions with the same counterparties within the same Targa entity, and would reduce our maximum loss due to counterparty credit risk by $30.6 million as of September 30, 2016. The range of losses attributable to our individual counterparties would be between less than $0.5 million and $13.7 million, depending on the counterparty in default.

Customer Credit Risk

We extend credit to customers and other parties in the normal course of business. We have an established policy and various procedures to manage our credit exposure risk, including initial and subsequent credit risk analyses, credit limits and terms and credit enhancements when necessary. We use credit enhancements including (but not limited to) letters of credit, prepayments, parental guarantees and rights of offset to limit credit risk to ensure that our established credit criteria are followed and financial loss is mitigated or minimized.

We have an active credit management process, which is focused on controlling loss exposure to bankruptcies or other liquidity issues of counterparties. If an assessment of uncollectible accounts resulted in a 1% reduction of our third-party accounts receivable, annual operating income would decrease by $5.5 million in the year of the assessment.

 

 

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered in this Quarterly Report. Based on this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were not effective as a result of a material weakness in our internal control over financial reporting as disclosed in our 2015 Annual Report on Form 10-K. Management has concluded that the material weakness that was present as of December 31, 2015 was also present as of September 30, 2016.

Previously Identified Material Weakness in Internal Control Over Financial Reporting

As previously disclosed in our 2015 Annual Report on Form 10-K, we did not maintain adequate controls over the valuation of certain assets in the Atlas mergers. Specifically, our review procedures over the development and application of inputs, assumptions, and calculations used in cash flow-based fair value measurements associated with business combinations did not operate as designed and at an appropriate level of detail commensurate with our financial reporting requirements.

Remediation Status

We have enhanced our internal control framework applicable to business acquisitions to include formal processes covering the development, application and review of inputs, assumptions, and calculations used in cash flow-based value measurements. Cash flow-based fair value measurements are also typically used for asset and goodwill impairment testing. We have not had any events or conditions since December 31, 2015 that have required the use of cash flow-based fair value measurements. As such, neither we nor our external auditors have had the opportunity to fully test the operating effectiveness of our remediated internal control framework. We will be able to fully test our remediated controls over cash flow-based fair value measurements when we perform our annual goodwill impairment testing for the 2016 reporting cycle, or earlier if another need arises for such value measurements.

Changes in Internal Control Over Financial Reporting During the Quarter Ended September 30, 2016

During the three months ended September 30, 2016, there have not been any changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

 

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings.

The information required for this item is provided in Note 15 – Contingencies, under the heading “Legal Proceedings” included in the Notes to Consolidated Financial Statements included under Part I, Item 1 of this Quarterly Report, which is incorporated by reference into this item.

Item 1A. Risk Factors.

For an in-depth discussion of our risk factors, see “Part I—Item 1A. Risk Factors” of our 2015 Annual Report, except for the additional risk factor discussed below. All of these risks and uncertainties could adversely affect our business, financial condition and/or results of operations.

Changes in future business conditions could cause recorded goodwill and property, plant and equipment assets to become further impaired, and our financial condition and results of operations could suffer if there is an additional impairment of goodwill or other intangible assets with indefinite lives, intangible assets with definite lives, or property, plant and equipment assets.

During 2015, global oil and natural gas commodity prices, particularly crude oil, significantly decreased as compared to 2014, and global oil and natural gas commodity prices remained depressed in the third quarter of 2016. This decrease in commodity prices has had, and is expected to continue to have, a negative impact on the demand for our services and our market capitalization. Should energy industry conditions further deteriorate, there is a possibility that goodwill, intangible assets and property, plant and equipment may be impaired in a future period. Any additional impairment charges that we may take in the future could be material to our financial results. We cannot accurately predict the amount and timing of any impairment of goodwill, intangible assets or property, plant and equipment. For a further discussion of our impairments, see Note 4 – Business Acquisitions of the Consolidated Financial Statements included in this Quarterly Report.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Recent Sales of Unregistered Securities

On September 30, 2016, Targa and certain of its subsidiaries made capital contributions to us of $215.0 million, for which we issued to Targa and certain of its subsidiaries 6,925,591 common units and 141,338 general partner units. The units were issued pursuant to the exemption offered by Section 4(a)(2) of the Securities Act.

Repurchase of Equity by Targa Resources Partners LP or Affiliated Purchasers

Not applicable.

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information

Not applicable.

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Item 6. Exhibits

 

66

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67

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

68

Exhibit 4.5

 

SUPPLEMENTAL INDENTURE

 

 

Supplemental Indenture (this “Supplemental Indenture”), dated as of October 11, 2016, among each of the parties identified under the caption “Guaranteeing Subsidiaries” on the signature page hereto (the “Guaranteeing Subsidiaries” and each individually, a “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

 

W I T N E S S E T H

 

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of February 2, 2011 providing for the issuance of 6⅞% Senior Notes due 2021 (the “Notes”);

 

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiaries shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiaries shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and

 

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

 

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

 

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

 

2. Agreement to Guarantee. Each Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Indenture including but not limited to Article 10 thereof.

 

3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of any Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or any Guaranteeing Subsidiary under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities

 

---

 

under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

 

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

 

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Issuers.

 

 

Signature pages follow.

 

---

 

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

 

GUARANTEEING SUBSIDIARIES

 

SLIDER WESTOK GATHERING, LLC

TARGA CHANEY DELL LLC

TARGA MIDKIFF LLC

TARGA PIPELINE MID-CONTINENT HOLDINGS LLC

TARGA PIPELINE MID-CONTINENT LLC

TARGA PIPELINE PARTNERS GP LLC

TPL ARKOMA HOLDINGS LLC

TPL ARKOMA INC.

TPL ARKOMA MIDSTREAM LLC

TPL GAS TREATING LLC

TPL LAUREL MOUNTAIN LLC

TPL SOUTHTEX MIDSTREAM LLC

TPL SOUTHTEX PIPELINE COMPANY LLC

VELMA INTRASTATE GAS TRANSMISSION COMPANY, LLC

 

By: /s/ Chris McEwan

Name: Chris McEwan

 

 

 

 

TARGA PIPELINE OPERATING PARTNERSHIP LP

TARGA PIPELINE PARTNERS LP

 

 

By: Targa Pipeline Partners GP LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

 

Signature Page to Supplemental Indenture (February 2, 2011 Indenture)

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TPL BARNETT LLC

 

By: Targa Pipeline Mid-Continent Holdings LLC, its sole

member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

PECOS PIPELINE LLC

TESUQUE PIPELINE, LLC

 

By: TPL Barnett LLC, its sole member

 

By: Targa Pipeline Mid-Continent Holdings LLC, its sole member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

VELMA GAS PROCESSING COMPANY, LLC

By: Targa Pipeline Mid-Continent LLC, its sole member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

Signature Page to Supplemental Indenture (February 2, 2011 Indenture)

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TARGA SOUTHTEX MIDSTREAM COMPANY LP

TPL SOUTHTEX GAS UTILITY COMPANY LP

TPL SOUTHTEX MIDSTREAM HOLDING  COMPANY LP

TPL SOUTHTEX PROCESSING COMPANY LP

TPL SOUTHTEX TRANSMISSION COMPANY LP

 

By: TPL SouthTex Pipeline Company LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

 

Signature Page to Supplemental Indenture (February 2, 2011 Indenture)

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ISSUERS

 

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

TARGA RESOURCES PARTNERS FINANCE CORPORATION

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

Signature Page to Supplemental Indenture (February 2, 2011 Indenture)

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TRUSTEE

 

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

 

 

By: /s/ Shazia Flores

Authorized Signatory

 

Signature Page to Supplemental Indenture (February 2, 2011 Indenture)

Exhibit 4.6

 

SUPPLEMENTAL INDENTURE

 

 

Supplemental Indenture (this “Supplemental Indenture”), dated as of October 11, 2016, among each of the parties identified under the caption “Guaranteeing Subsidiary” on the signature page hereto (the “Guaranteeing Subsidiaries” and each individually, a “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

 

W I T N E S S E T H

 

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of January 31, 2012 providing for the issuance of 6 3/8% Senior Notes due 2022 (the “Notes”);

 

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiaries shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiaries shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and

 

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

 

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

 

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

 

2. Agreement to Guarantee. Each Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Indenture including but not limited to Article 10 thereof.

 

3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of any Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or any Guaranteeing Subsidiary under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities

 

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under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

 

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

 

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Issuers.

 

 

Signature pages follow.

 

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IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

 

GUARANTEEING SUBSIDIARIES

 

SLIDER WESTOK GATHERING, LLC

TARGA CHANEY DELL LLC

TARGA MIDKIFF LLC

TARGA PIPELINE MID-CONTINENT HOLDINGS LLC

TARGA PIPELINE MID-CONTINENT LLC

TARGA PIPELINE PARTNERS GP LLC

TPL ARKOMA HOLDINGS LLC

TPL ARKOMA INC.

TPL ARKOMA MIDSTREAM LLC

TPL GAS TREATING LLC

TPL LAUREL MOUNTAIN LLC

TPL SOUTHTEX MIDSTREAM LLC

TPL SOUTHTEX PIPELINE COMPANY LLC

VELMA INTRASTATE GAS TRANSMISSION COMPANY, LLC

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

TARGA PIPELINE OPERATING PARTNERSHIP LP

TARGA PIPELINE PARTNERS LP

 

 

By: Targa Pipeline Partners GP LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

 

 

Signature Page to Supplemental Indenture (January 31, 2012 Indenture)

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TPL BARNETT LLC

 

By: Targa Pipeline Mid-Continent Holdings LLC, its sole

member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

PECOS PIPELINE LLC

TESUQUE PIPELINE, LLC

 

By: TPL Barnett LLC, its sole member

 

By: Targa Pipeline Mid-Continent Holdings LLC, its sole member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

VELMA GAS PROCESSING COMPANY, LLC

By: Targa Pipeline Mid-Continent LLC, its sole member

 

 

By: /s/ Chris McEwan

Name: Chris McEwan

Signature Page to Supplemental Indenture (January 31, 2012 Indenture)

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TARGA SOUTHTEX MIDSTREAM COMPANY LP

TPL SOUTHTEX GAS UTILITY COMPANY LP

TPL SOUTHTEX MIDSTREAM HOLDING  COMPANY LP

TPL SOUTHTEX PROCESSING COMPANY LP

TPL SOUTHTEX TRANSMISSION COMPANY LP

 

By: TPL SouthTex Pipeline Company LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

 

Signature Page to Supplemental Indenture (January 31, 2012 Indenture)

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ISSUERS

 

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

TARGA RESOURCES PARTNERS FINANCE CORPORATION

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

Signature Page to Supplemental Indenture (January 31, 2012 Indenture)

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TRUSTEE

 

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

 

 

By: /s/ Shazia Flores

Authorized Signatory

 

Signature Page to Supplemental Indenture (January 31, 2012 Indenture)

Exhibit 4.7

 

SUPPLEMENTAL INDENTURE

 

 

Supplemental Indenture (this “Supplemental Indenture”), dated as of October 11, 2016, among each of the parties identified under the caption “Guaranteeing Subsidiaries” on the signature page hereto (the “Guaranteeing Subsidiaries” and each individually, a “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

 

W I T N E S S E T H

 

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of October 25, 2012 providing for the issuance of 5 1/4% Senior Notes due 2023 (the “Notes”);

 

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiaries shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiaries shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and

 

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

 

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

 

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

 

2. Agreement to Guarantee. Each Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Indenture including but not limited to Article 10 thereof.

 

3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of any Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or any Guaranteeing Subsidiary under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities

 

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under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

 

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

 

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Issuers.

 

 

Signature pages follow.

 

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IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

 

GUARANTEEING SUBSIDIARIES

 

SLIDER WESTOK GATHERING, LLC

TARGA CHANEY DELL LLC

TARGA MIDKIFF LLC

TARGA PIPELINE MID-CONTINENT HOLDINGS LLC

TARGA PIPELINE MID-CONTINENT LLC

TARGA PIPELINE PARTNERS GP LLC

TPL ARKOMA HOLDINGS LLC

TPL ARKOMA INC.

TPL ARKOMA MIDSTREAM LLC

TPL GAS TREATING LLC

TPL LAUREL MOUNTAIN LLC

TPL SOUTHTEX MIDSTREAM LLC

TPL SOUTHTEX PIPELINE COMPANY LLC

VELMA INTRASTATE GAS TRANSMISSION COMPANY, LLC

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

TARGA PIPELINE OPERATING PARTNERSHIP LP

TARGA PIPELINE PARTNERS LP

 

 

By: Targa Pipeline Partners GP LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

 

 

Signature Page to Supplemental Indenture (October 25, 2012 Indenture)

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TPL BARNETT LLC

 

By: Targa Pipeline Mid-Continent Holdings LLC, its sole

member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

PECOS PIPELINE LLC

TESUQUE PIPELINE, LLC

 

By: TPL Barnett LLC, its sole member

 

By: Targa Pipeline Mid-Continent Holdings LLC, its sole member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

VELMA GAS PROCESSING COMPANY, LLC

By: Targa Pipeline Mid-Continent LLC, its sole member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

Signature Page to Supplemental Indenture (October 25, 2012 Indenture)

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TARGA SOUTHTEX MIDSTREAM COMPANY LP

TPL SOUTHTEX GAS UTILITY COMPANY LP

TPL SOUTHTEX MIDSTREAM HOLDING  COMPANY LP

TPL SOUTHTEX PROCESSING COMPANY LP

TPL SOUTHTEX TRANSMISSION COMPANY LP

 

By: TPL SouthTex Pipeline Company LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

 

Signature Page to Supplemental Indenture (October 25, 2012 Indenture)

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ISSUERS

 

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

TARGA RESOURCES PARTNERS FINANCE CORPORATION

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

Signature Page to Supplemental Indenture (October 25, 2012 Indenture)

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TRUSTEE

 

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

 

 

By: /s/ Shazia Flores

Authorized Signatory

 

Signature Page to Supplemental Indenture (October 25, 2012 Indenture)

Exhibit 4.8

 

SUPPLEMENTAL INDENTURE

 

 

Supplemental Indenture (this “Supplemental Indenture”), dated as of October 11, 2016, among each of the parties identified under the caption “Guaranteeing Subsidiaries” on the signature page hereto (the “Guaranteeing Subsidiaries” and each individually, a “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

 

W I T N E S S E T H

 

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of May 14, 2013 providing for the issuance of 4 1/4% Senior Notes due 2023 (the “Notes”);

 

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiaries shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiaries shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and

 

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

 

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

 

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

 

2. Agreement to Guarantee. Each Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Indenture including but not limited to Article 10 thereof.

 

3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of any Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or any Guaranteeing Subsidiary under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities

 

---

 

under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

 

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

 

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Issuers.

 

 

Signature pages follow.

 

---

 

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

 

GUARANTEEING SUBSIDIARIES

 

SLIDER WESTOK GATHERING, LLC

TARGA CHANEY DELL LLC

TARGA MIDKIFF LLC

TARGA PIPELINE MID-CONTINENT HOLDINGS LLC

TARGA PIPELINE MID-CONTINENT LLC

TARGA PIPELINE PARTNERS GP LLC

TPL ARKOMA HOLDINGS LLC

TPL ARKOMA INC.

TPL ARKOMA MIDSTREAM LLC

TPL GAS TREATING LLC

TPL LAUREL MOUNTAIN LLC

TPL SOUTHTEX MIDSTREAM LLC

TPL SOUTHTEX PIPELINE COMPANY LLC

VELMA INTRASTATE GAS TRANSMISSION COMPANY, LLC

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

TARGA PIPELINE OPERATING PARTNERSHIP LP

TARGA PIPELINE PARTNERS LP

 

 

By: Targa Pipeline Partners GP LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

 

 

Signature Page to Supplemental Indenture (May 14, 2013 Indenture)

---

 

TPL BARNETT LLC

 

By: Targa Pipeline Mid-Continent Holdings LLC, its sole

member

 

 

By: /s/ Chris McEwan

Name: Chris McEwan

 

 

PECOS PIPELINE LLC

TESUQUE PIPELINE, LLC

 

By: TPL Barnett LLC, its sole member

 

By: Targa Pipeline Mid-Continent Holdings LLC, its sole member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

VELMA GAS PROCESSING COMPANY, LLC

By: Targa Pipeline Mid-Continent LLC, its sole member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

Signature Page to Supplemental Indenture (May 14, 2013 Indenture)

---

 

TARGA SOUTHTEX MIDSTREAM COMPANY LP

TPL SOUTHTEX GAS UTILITY COMPANY LP

TPL SOUTHTEX MIDSTREAM HOLDING  COMPANY LP

TPL SOUTHTEX PROCESSING COMPANY LP

TPL SOUTHTEX TRANSMISSION COMPANY LP

 

By: TPL SouthTex Pipeline Company LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

 

Signature Page to Supplemental Indenture (May 14, 2013 Indenture)

---

 

ISSUERS

 

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

TARGA RESOURCES PARTNERS FINANCE CORPORATION

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

Signature Page to Supplemental Indenture (May 14, 2013 Indenture)

---

 

TRUSTEE

 

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

 

 

By: /s/ Shazia Flores

Authorized Signatory

 

Signature Page to Supplemental Indenture (May 14, 2013 Indenture)

Exhibit 4.9

 

SUPPLEMENTAL INDENTURE

 

 

Supplemental Indenture (this “Supplemental Indenture”), dated as of October 11, 2016, among each of the parties identified under the caption “Guaranteeing Subsidiaries” on the signature page hereto (the “Guaranteeing Subsidiaries” and each individually, a “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

 

W I T N E S S E T H

 

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of October 28, 2014 providing for the issuance of 4.125% Senior Notes due 2019 (the “Notes”);

 

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiaries shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiaries shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and

 

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

 

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

 

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

 

2. Agreement to Guarantee. Each Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Indenture including but not limited to Article 10 thereof.

 

3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of any Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or any Guaranteeing Subsidiary under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities

 

---

 

under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

 

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

 

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Issuers.

 

 

Signature pages follow.

 

---

 

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

 

GUARANTEEING SUBSIDIARIES

 

SLIDER WESTOK GATHERING, LLC

TARGA CHANEY DELL LLC

TARGA MIDKIFF LLC

TARGA PIPELINE MID-CONTINENT HOLDINGS LLC

TARGA PIPELINE MID-CONTINENT LLC

TARGA PIPELINE PARTNERS GP LLC

TPL ARKOMA HOLDINGS LLC

TPL ARKOMA INC.

TPL ARKOMA MIDSTREAM LLC

TPL GAS TREATING LLC

TPL LAUREL MOUNTAIN LLC

TPL SOUTHTEX MIDSTREAM LLC

TPL SOUTHTEX PIPELINE COMPANY LLC

VELMA INTRASTATE GAS TRANSMISSION COMPANY, LLC

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

TARGA PIPELINE OPERATING PARTNERSHIP LP

TARGA PIPELINE PARTNERS LP

 

 

By: Targa Pipeline Partners GP LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

 

Signature Page to Supplemental Indenture (October 28, 2014 Indenture)

---

 

TPL BARNETT LLC

 

By: Targa Pipeline Mid-Continent Holdings LLC, its sole

member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

PECOS PIPELINE LLC

TESUQUE PIPELINE, LLC

 

By: TPL Barnett LLC, its sole member

 

By: Targa Pipeline Mid-Continent Holdings LLC, its sole member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

VELMA GAS PROCESSING COMPANY, LLC

By: Targa Pipeline Mid-Continent LLC, its sole member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

Signature Page to Supplemental Indenture (October 28, 2014 Indenture)

---

 

TARGA SOUTHTEX MIDSTREAM COMPANY LP

TPL SOUTHTEX GAS UTILITY COMPANY LP

TPL SOUTHTEX MIDSTREAM HOLDING  COMPANY LP

TPL SOUTHTEX PROCESSING COMPANY LP

TPL SOUTHTEX TRANSMISSION COMPANY LP

 

By: TPL SouthTex Pipeline Company LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

 

Signature Page to Supplemental Indenture (October 28, 2014 Indenture)

---

 

ISSUERS

 

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

TARGA RESOURCES PARTNERS FINANCE CORPORATION

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

Signature Page to Supplemental Indenture (October 28, 2014 Indenture)

---

 

TRUSTEE

 

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

 

 

By: /s/ Shazia Flores

Authorized Signatory

 

Signature Page to Supplemental Indenture (October 28, 2014 Indenture)

Exhibit 4.10

 

SUPPLEMENTAL INDENTURE

 

 

Supplemental Indenture (this “Supplemental Indenture”), dated as of October 11, 2016, among each of the parties identified under the caption “Guaranteeing Subsidiaries” on the signature page hereto (the “Guaranteeing Subsidiaries” and each individually, a “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

 

W I T N E S S E T H

 

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of January 30, 2015 providing for the issuance of 5% Senior Notes due 2018 (the “Notes”);

 

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiaries shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiaries shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and

 

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

 

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

 

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

 

2. Agreement to Guarantee. Each Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Indenture including but not limited to Article 10 thereof.

 

3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of any Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or any Guaranteeing Subsidiary under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities

 

---

 

under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

 

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

 

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Issuers.

 

 

Signature pages follow.

 

---

 

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

 

GUARANTEEING SUBSIDIARIES

 

SLIDER WESTOK GATHERING, LLC

TARGA CHANEY DELL LLC

TARGA MIDKIFF LLC

TARGA PIPELINE MID-CONTINENT HOLDINGS LLC

TARGA PIPELINE MID-CONTINENT LLC

TARGA PIPELINE PARTNERS GP LLC

TPL ARKOMA HOLDINGS LLC

TPL ARKOMA INC.

TPL ARKOMA MIDSTREAM LLC

TPL GAS TREATING LLC

TPL LAUREL MOUNTAIN LLC

TPL SOUTHTEX MIDSTREAM LLC

TPL SOUTHTEX PIPELINE COMPANY LLC

VELMA INTRASTATE GAS TRANSMISSION COMPANY, LLC

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

TARGA PIPELINE OPERATING PARTNERSHIP LP

TARGA PIPELINE PARTNERS LP

 

 

By: Targa Pipeline Partners GP LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

Signature Page to Supplemental Indenture (January 30, 2015 Indenture)

---

 

TPL BARNETT LLC

 

By: Targa Pipeline Mid-Continent Holdings LLC, its sole

member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

PECOS PIPELINE LLC

TESUQUE PIPELINE, LLC

 

By: TPL Barnett LLC, its sole member

 

By: Targa Pipeline Mid-Continent Holdings LLC, its sole member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

VELMA GAS PROCESSING COMPANY, LLC

By: Targa Pipeline Mid-Continent LLC, its sole member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

Signature Page to Supplemental Indenture (January 30, 2015 Indenture)

---

 

TARGA SOUTHTEX MIDSTREAM COMPANY LP

TPL SOUTHTEX GAS UTILITY COMPANY LP

TPL SOUTHTEX MIDSTREAM HOLDING  COMPANY LP

TPL SOUTHTEX PROCESSING COMPANY LP

TPL SOUTHTEX TRANSMISSION COMPANY LP

 

By: TPL SouthTex Pipeline Company LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

Signature Page to Supplemental Indenture (January 30, 2015 Indenture)

---

 

ISSUERS

 

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

TARGA RESOURCES PARTNERS FINANCE CORPORATION

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

Signature Page to Supplemental Indenture (January 30, 2015 Indenture)

---

 

TRUSTEE

 

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

 

 

By: /s/ Shazia Flores

Authorized Signatory

 

Signature Page to Supplemental Indenture (January 30, 2015 Indenture)

Exhibit 4.11

 

SUPPLEMENTAL INDENTURE

 

 

Supplemental Indenture (this “Supplemental Indenture”), dated as of October 11, 2016, among each of the parties identified under the caption “Guaranteeing Subsidiaries” on the signature page hereto (the “Guaranteeing Subsidiaries” and each individually, a “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

 

W I T N E S S E T H

 

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of May 11, 2015 providing for the issuance of the Issuers’ 6.625% Senior Notes due 2020 (the “Notes”);

 

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiaries shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiaries shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and

 

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

 

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

 

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

 

2. Agreement to Guarantee. Each Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Indenture including but not limited to Article 10 thereof.

 

3. No Recourse Against Others. No past, present or future director, officer, partner, member, employee, incorporator, manager or owner of any Equity Interests of any Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or any Guarantor under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes.

 

 

---

 

4. NEW YORK LAW TO GOVERN. THE LAWS OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

 

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Issuers.

 

 

Signature pages follow.

 

---

 

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

 

GUARANTEEING SUBSIDIARIES

 

SLIDER WESTOK GATHERING, LLC

TARGA CHANEY DELL LLC

TARGA MIDKIFF LLC

TARGA PIPELINE MID-CONTINENT HOLDINGS LLC

TARGA PIPELINE MID-CONTINENT LLC

TARGA PIPELINE PARTNERS GP LLC

TPL ARKOMA HOLDINGS LLC

TPL ARKOMA INC.

TPL ARKOMA MIDSTREAM LLC

TPL GAS TREATING LLC

TPL LAUREL MOUNTAIN LLC

TPL SOUTHTEX MIDSTREAM LLC

TPL SOUTHTEX PIPELINE COMPANY LLC

VELMA INTRASTATE GAS TRANSMISSION COMPANY, LLC

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

 

TARGA PIPELINE OPERATING PARTNERSHIP LP

TARGA PIPELINE PARTNERS LP

 

 

By: Targa Pipeline Partners GP LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

 

 

Signature Page to Supplemental Indenture (May 11, 2015 Indenture)

---

 

TPL BARNETT LLC

 

By: Targa Pipeline Mid-Continent Holdings LLC, its sole

member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

PECOS PIPELINE LLC

TESUQUE PIPELINE, LLC

 

By: TPL Barnett LLC, its sole member

 

By: Targa Pipeline Mid-Continent Holdings LLC, its sole member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

VELMA GAS PROCESSING COMPANY, LLC

By: Targa Pipeline Mid-Continent LLC, its sole member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

Signature Page to Supplemental Indenture (May 11, 2015 Indenture)

---

 

TARGA SOUTHTEX MIDSTREAM COMPANY LP

TPL SOUTHTEX GAS UTILITY COMPANY LP

TPL SOUTHTEX MIDSTREAM HOLDING  COMPANY LP

TPL SOUTHTEX PROCESSING COMPANY LP

TPL SOUTHTEX TRANSMISSION COMPANY LP

 

By: TPL SouthTex Pipeline Company LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

Signature Page to Supplemental Indenture (May 11, 2015 Indenture)

---

 

ISSUERS

 

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

TARGA RESOURCES PARTNERS FINANCE CORPORATION

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

Signature Page to Supplemental Indenture (May 11, 2015 Indenture)

---

 

TRUSTEE

 

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

 

 

By: /s/ Shazia Flores

Authorized Signatory

 

Signature Page to Supplemental Indenture (May 11, 2015 Indenture)

Exhibit 4.12

 

SUPPLEMENTAL INDENTURE

 

 

Supplemental Indenture (this “Supplemental Indenture”), dated as of October 11, 2016, among each of the parties identified under the caption “Guaranteeing Subsidiaries” on the signature page hereto (the “Guaranteeing Subsidiaries” and each individually, a “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

 

W I T N E S S E T H

 

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of September 14, 2015 providing for the issuance of 6 3/4% Senior Notes due 2024 (the “Notes”);

 

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiaries shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiaries shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and

 

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

 

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

 

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

 

2. Agreement to Guarantee. Each Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Indenture including but not limited to Article 10 thereof.

 

3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of any Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or any Guaranteeing Subsidiary under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities

 

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under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

 

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

 

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Issuers.

 

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IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

 

GUARANTEEING SUBSIDIARIES

 

SLIDER WESTOK GATHERING, LLC

TARGA CHANEY DELL LLC

TARGA MIDKIFF LLC

TARGA PIPELINE MID-CONTINENT HOLDINGS LLC

TARGA PIPELINE MID-CONTINENT LLC

TARGA PIPELINE PARTNERS GP LLC

TPL ARKOMA HOLDINGS LLC

TPL ARKOMA INC.

TPL ARKOMA MIDSTREAM LLC

TPL GAS TREATING LLC

TPL LAUREL MOUNTAIN LLC

TPL SOUTHTEX MIDSTREAM LLC

TPL SOUTHTEX PIPELINE COMPANY LLC

VELMA INTRASTATE GAS TRANSMISSION COMPANY, LLC

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

TARGA PIPELINE OPERATING PARTNERSHIP LP

TARGA PIPELINE PARTNERS LP

 

 

By: Targa Pipeline Partners GP LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

 

 

Signature Page to Supplemental Indenture (September 14, 2015 Indenture)

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TPL BARNETT LLC

 

By: Targa Pipeline Mid-Continent Holdings LLC, its sole

member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

PECOS PIPELINE LLC

TESUQUE PIPELINE, LLC

 

By: TPL Barnett LLC, its sole member

 

By: Targa Pipeline Mid-Continent Holdings LLC, its sole member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

VELMA GAS PROCESSING COMPANY, LLC

By: Targa Pipeline Mid-Continent LLC, its sole member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

Signature Page to Supplemental Indenture (September 14, 2015 Indenture)

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TARGA SOUTHTEX MIDSTREAM COMPANY LP

TPL SOUTHTEX GAS UTILITY COMPANY LP

TPL SOUTHTEX MIDSTREAM HOLDING  COMPANY LP

TPL SOUTHTEX PROCESSING COMPANY LP

TPL SOUTHTEX TRANSMISSION COMPANY LP

 

By: TPL SouthTex Pipeline Company LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

 

Signature Page to Supplemental Indenture (September 14, 2015 Indenture)

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ISSUERS

 

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

TARGA RESOURCES PARTNERS FINANCE CORPORATION

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

Signature Page to Supplemental Indenture (September 14, 2015 Indenture)

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TRUSTEE

 

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

 

 

By: /s/ Shazia Flores

Authorized Signatory

 

Signature Page to Supplemental Indenture (September 14, 2015 Indenture)

Exhibit 4.13

 

SUPPLEMENTAL INDENTURE

 

 

Supplemental Indenture (this “Supplemental Indenture”), dated as of October 11, 2016, among each of the parties identified under the caption “Guaranteeing Subsidiaries” on the signature page hereto (the “Guaranteeing Subsidiaries” and each individually, a “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

 

W I T N E S S E T H

 

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of October 6, 2016 providing for the issuance of 5 1/8% Senior Notes due 2025 and 5 3/8% Senior Notes due 2027 (collectively, the “Notes”);

 

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiaries shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiaries shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and

 

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

 

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

 

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

 

2. Agreement to Guarantee. Each Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Indenture including but not limited to Article 10 thereof.

 

3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of any Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or any Guaranteeing Subsidiary under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities

 

---

 

under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

 

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

 

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Issuers.

 

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IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

 

GUARANTEEING SUBSIDIARIES

 

SLIDER WESTOK GATHERING, LLC

TARGA CHANEY DELL LLC

TARGA MIDKIFF LLC

TARGA PIPELINE MID-CONTINENT HOLDINGS LLC

TARGA PIPELINE MID-CONTINENT LLC

TARGA PIPELINE PARTNERS GP LLC

TPL ARKOMA HOLDINGS LLC

TPL ARKOMA INC.

TPL ARKOMA MIDSTREAM LLC

TPL GAS TREATING LLC

TPL LAUREL MOUNTAIN LLC

TPL SOUTHTEX MIDSTREAM LLC

TPL SOUTHTEX PIPELINE COMPANY LLC

VELMA INTRASTATE GAS TRANSMISSION COMPANY, LLC

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

TARGA PIPELINE OPERATING PARTNERSHIP LP

TARGA PIPELINE PARTNERS LP

 

 

By: Targa Pipeline Partners GP LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

 

 

Signature Page to Supplemental Indenture (October 6, 2016 Indenture)

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TPL BARNETT LLC

 

By: Targa Pipeline Mid-Continent Holdings LLC, its sole

member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

PECOS PIPELINE LLC

TESUQUE PIPELINE, LLC

 

By: TPL Barnett LLC, its sole member

 

By: Targa Pipeline Mid-Continent Holdings LLC, its sole member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

VELMA GAS PROCESSING COMPANY, LLC

By: Targa Pipeline Mid-Continent LLC, its sole member

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

Signature Page to Supplemental Indenture (October 6, 2016 Indenture)

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TARGA SOUTHTEX MIDSTREAM COMPANY LP

TPL SOUTHTEX GAS UTILITY COMPANY LP

TPL SOUTHTEX MIDSTREAM HOLDING  COMPANY LP

TPL SOUTHTEX PROCESSING COMPANY LP

TPL SOUTHTEX TRANSMISSION COMPANY LP

 

By: TPL SouthTex Pipeline Company LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

 

Signature Page to Supplemental Indenture (October 6, 2016 Indenture)

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ISSUERS

 

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

TARGA RESOURCES PARTNERS FINANCE CORPORATION

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

 

 

Signature Page to Supplemental Indenture (October 6, 2016 Indenture)

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TRUSTEE

 

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

 

 

By: /s/ Shazia Flores

Authorized Signatory

 

Signature Page to Supplemental Indenture (October 6, 2016 Indenture)

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Joe Bob Perkins, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Targa Resources Partners LP (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 4, 2016

 

 

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Matthew J. Meloy, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Targa Resources Partners LP (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 4, 2016

 

 

 

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Targa Resources Partners LP (the “Partnership”) for the three months ended September 30, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Joe Bob Perkins, as Chief Executive Officer of Targa Resources GP LLC, the general partner of the Partnership, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

 

Date: November 4, 2016

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

 

 

 

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Targa Resources Partners LP (the “Partnership”) for the three months ended September 30, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Matthew J. Meloy, as Chief Financial Officer of Targa Resources GP LLC, the general partner of the Partnership, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

 

Date: November 4, 2016

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.