UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the quarterly period ended March 31, 2017

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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) 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 May 1, 2017, there were 5,000,000 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units outstanding.

 

 

 

 

 

 

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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 on Form 10-Q for the quarter ended March 31, 2017 (“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)

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,” “TRP,” 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 pursuant to the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement”, and such transactions, 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 TRC/TRP Merger Agreement, Merger Sub merged with and into TRP 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”) that were issued in October 2015 remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.”

 

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 became effective as of December 1, 2016. The Third A&R Partnership Agreement amendments include among other things (i) eliminating the incentive distribution rights (“IDRs”) held by the general partner, and related distribution and allocation provisions, (ii) eliminating the Special General Partner Interest (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:

 

See Note 19 – Segment Information for certain financial information regarding 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.

 

 

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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 months ended March 31, 2017 and 2016 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 months ended March 31, 2017 are not necessarily indicative of the results that may be expected for the full year.

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. There were no significant updates or revisions to our policies during the three months ended March 31, 2017, 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 (1) identifying the contracts with customers, (2) identifying the performance obligations in the contracts, (3) determining the transaction price, (4) allocating the transaction price to the performance obligations, and (5) 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 retrospectively 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 standard 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.

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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.

In December 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. The amendments in this update clarify the disclosure requirements for performance obligations, provide optional exemptions from the disclosure requirement for remaining performance obligations for specific situations in which an entity need not estimate variable consideration to recognize revenue and provide clarified guidance regarding impairment testing of capitalized contract costs.

We expect to adopt this new revenue recognition standard on January 1, 2018, presenting a cumulative effect adjustment in the period the standard is adopted. We also anticipate electing the practical expedient to apply the guidance retrospectively to only those contracts that are not completed contracts at the date of initial application. We have disaggregated contracts within our two segments and are in the process of reviewing contracts and transaction types with counterparties in order to evaluate how the new standard would impact our current revenue recognition and disclosure policies upon adoption. In addition, we are also evaluating whether certain contracts within our gathering and processing segment create relationships with counterparties akin to suppliers or involve significant sharing of risks that would exclude such contracts from the scope of Topic 606.

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.

 

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, 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

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transfer until the asset has been sold to an outside party or otherwise recovered, 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. We early adopted the applicable amendments in first quarter of 2017 on a modified retrospective basis. The adoption resulted in no effect as TRP is not subject to income taxes.

 

Business Combinations

In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. The amendments clarify the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses by providing an initial required screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, then the amendments (1) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (2) remove the evaluation of whether a market participant could replace missing elements. The amendments also provide a framework to assist entities in evaluating whether both an input and a substantive process are present. These amendments are effective for annual periods beginning after December 15, 2017, including interim periods within those periods, with early application permitted for transactions that have not been previously reported. We are currently evaluating the effects of such amendments.

 

Goodwill Impairment

In January 2017, FASB issued ASU 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, which eliminates Step 2 from the goodwill impairment test. Step 2 required entities to compute the implied fair value of goodwill if it was determined that the carrying amount of a reporting unit exceeded its fair value. Under the amendments in this update, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount and should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value. The goodwill impairment recognized should not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. These amendments are effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We expect to apply these amendments for our annual goodwill impairment test as of November 30, 2017, or earlier if events or changes in circumstances indicate that an interim goodwill impairment test is necessary.

 

Other Income

In February 2017, FASB issued ASU 2017-05, Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20), which clarifies the scope of Subtopic 610-20 and adds guidance for partial sales of nonfinancial assets. Specifically, the amendments clarify that the guidance applies to all nonfinancial assets and in substance nonfinancial assets unless other specific guidance applies and defines "in substance financial asset" as an asset or group of assets for which substantially all of the fair value consists of nonfinancial assets and the group or subsidiary is not a business. The amendment also impacts the accounting for partial sales of nonfinancial assets, whereby an entity that transfers its controlling interest in a nonfinancial asset, but retains a noncontrolling ownership interest, will measure the retained interest at fair value resulting in the full gain/loss recognition upon sale. The amendment is 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 amendment on our consolidated financial statements. 

 

 

 

 

 

 

 

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Note 4 – Business Acquisitions and Divestitures

 

2017 Acquisition

 

Permian Acquisition

 

On March 1, 2017, we completed the purchase of 100% of the membership interests of Outrigger Delaware Operating, LLC, Outrigger Southern Delaware Operating, LLC (together “New Delaware”) and Outrigger Midland Operating, LLC (“New Midland” and together with New Delaware, the “Permian Acquisition”).

 

We paid $484.1 million in cash at closing on March 1, 2017, and will pay $90.0 million within 90 days of closing (collectively, the “initial purchase price”). Contributions from TRC were used to fund the cash portion of the Permian Acquisition purchase price. Subject to certain performance-linked measures and other conditions, additional cash of up to $935.0 million may be payable to the sellers of New Delaware and New Midland in potential earn-out payments that may occur in 2018 and 2019. The potential earn-out payments will be based upon a multiple of realized gross margin from contracts that existed on March 1, 2017.

 

New Delaware’s gas gathering and processing and crude gathering assets are located in Loving, Winkler, Pecos and Ward counties in Texas. The operations are backed by producer dedications of more than 145,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 14 years. The New Delaware assets include 70 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the New Delaware system. Since March 1, 2017, financial and statistical data of New Delaware have been included in Sand Hills operations.

 

New Midland’s gas gathering and processing and crude gathering assets are located in Howard, Martin and Borden counties in Texas. The operations are backed by producer dedications of more than 105,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 13 years. The New Midland assets include 10 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the New Midland system. Since March 1, 2017, financial and statistical data of New Midland have been included in SAOU operations.

 

New Delaware’s gas gathering and processing assets were connected to our Sand Hills system in the first quarter of 2017 and we expect that New Midland’s gas gathering and processing assets will be connected to our existing WestTX system during 2017. We believe connecting the acquired assets to our legacy Permian footprint creates operational and capital synergies, and will afford enhanced flexibility in serving our producer customers.

 

The acquired businesses contributed revenues of $8.1 million and a net loss of $2.6 million to us for the period from March 1, 2017 to March 31, 2017, and are reported in our Gathering and Processing segment. As of March 31, 2017, we had incurred $5.1 million of acquisition-related costs. These expenses are included in Other expense in our Consolidated Statements of Operations for the three months ended March 31, 2017.

 

Pro Forma Impact of Permian Acquisition on Consolidated Statement of Operations

 

The following summarized unaudited pro forma Consolidated Statement of Operations information for the three months ended March 31, 2017 and March 31, 2016 assumes that the Permian Acquisition occurred as of January 1, 2016. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had we completed this acquisition as of January 1, 2016, or that would be attained in the future.

 

 

The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making the following adjustments to the unaudited results of the acquired businesses for the periods indicated:

 

 

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The following table summarizes the consideration transferred to acquire New Delaware and New Midland:

 

 

 

We accounted for the Permian Acquisition as an acquisition of a business under purchase accounting rules. The assets acquired and liabilities assumed related to the Permian Acquisition were recorded at their fair values as of the closing date of March 1, 2017. The fair values below are preliminary and subject to revisions pending the completion of the valuation and other post-closing adjustments. These and other estimates are subject to change as additional information becomes available and is assessed by us, and agreement is reached on the respective final settlement statements. The preliminary fair value of the assets acquired and liabilities assumed at the acquisition date is shown below:

 

 

Under the acquisition method of accounting, the assets acquired and liabilities assumed are recognized at their estimated fair values, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Such excess of purchase price over the fair value of net assets acquired was approximately $159.0 million, which was recorded as goodwill. As of March 31, 2017, this determination is based on our preliminary valuation and is subject to revisions pending the completion of the valuation and other adjustments. As a result, goodwill is also preliminary. The preliminary goodwill is attributable to expected operational and capital synergies. The goodwill is expected to be amortizable for tax purposes. The attribution of the goodwill to reporting units for the purpose of required future impairment assessments will be completed in conjunction with our finalization of the fair value determination.

 

The preliminary fair value of assets acquired included trade receivables of $6.5 million, all of which was expected to be collectible.

 

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 14 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation.

 

 

 

 

 

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Contingent Consideration

 

A contingent consideration liability arising from potential earn-out payments in connection with the Permian Acquisition has been recognized at its preliminary fair value. We agreed to pay up to an additional $935.0 million in potential earn-out payments that may occur in 2018 and 2019. The preliminary acquisition date fair value of the potential earn-out payments of $461.6 million was recorded within other long-term liabilities on our Consolidated Balance Sheets. Subsequent changes in the fair value of this liability, excluding any measurement period adjustments of the acquisition date fair value, are included in earnings. During the three months ended March 31, 2017, we recognized $3.2 million as Other expense related to the change in fair value of the contingent consideration. See Note 14 – Fair Value Measurements for additional discussion of the fair value methodology.

 

2017 Divestiture

 

Sale of Venice Gathering System, L.L.C.

 

Through our 76.8% ownership interest in Venice Energy Services Company, L.L.C. (“VESCO”), we have operated the Venice gas plant and the Venice gathering system. On April 4, 2017, VESCO entered into a purchase and sale agreement with Rosefield Pipeline Company, LLC, an affiliate of Arena Energy, LP, to sell its 100% ownership interests in Venice Gathering System, L.L.C. (“VGS”), a Delaware limited liability company engaged in the business of transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”), for approximately $0.4 million in cash. Additionally, the VGS asset retirement obligations (“ARO”) were assumed by the buyer. VGS owns and operates a natural gas gathering system in the Gulf of Mexico. Historically, VGS has been reported in our Gathering and Processing segment. After the sale of VGS, we continue to operate the Venice gas plant through our ownership in VESCO. Targa Midstream Services LLC will continue to operate the Venice gathering system for up to four months after closing pursuant to a Transition Services Agreement with VGS.

 

The sale of VGS closed on April 4, 2017, and as a result, we recognized a loss of $16.1 million in our Consolidated Statements of Operations as part of Other operating (income) expense to impair our basis in the VGS assets to its fair value.

 

 

Note 5 — Inventories

 

 

 

Note 6 — Property, Plant and Equipment and Intangible Assets

 

Property, Plant and Equipment

 

 

Intangible Assets

 

Intangible assets consist of customer contracts and customer relationships acquired in the Permian Acquisition in 2017, the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively, the “Atlas mergers”) and our Badlands acquisition in

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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 intangible assets acquired in the Permian Acquisition were recorded at a preliminary fair value of $625.6 million pending completion of final valuations. For the purposes of preparing the accompanying financial statements (which include one month of amortization of these intangible assets), we are amortizing these intangible assets over a 15-year life using the straight-line method. The amortization method and lives for the Permian Acquisition intangibles will be reviewed and possibly revised as we finalize the valuations over the upcoming months.

The intangible assets acquired in the Atlas mergers 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 estimated annual amortization expense for intangible assets, including the provisional Permian valuations and straight-line treatment is approximately $184.2 million, $177.4 million, $166.4 million, $154.2 million and $144.3 million for each of the years 2017 through 2021.

 

The changes in our intangible assets are as follows:

 

 

Note 7 – 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. During the first quarter of 2016, we finalized our 2015 impairment assessment and recorded additional impairment expense of $24.0 million on our Consolidated Statement of Operations. The impairment of goodwill was 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.

Changes in the net book value of our goodwill are as follows:

 

 

 

 

Note 8 – 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: a 75% interest in T2 LaSalle, a gas gathering company; a 50% interest in T2 Eagle Ford, a gas gathering company; and a 50% interest in T2 EF Cogen (“Cogen”), which owns a cogeneration facility, (together the “T2 Joint Ventures”). The T2 Joint Ventures were formed to provide services for the benefit of the joint interest owners. The T2 LaSalle and T2 Eagle Ford gathering companies have capacity lease agreements with the joint interest owners, which cover their costs of operations (excluding depreciation and amortization). 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:

 

 

(2)     Includes a $1.0 million contribution of property, plant and equipment to T2 Eagle Ford.

 

Our equity loss for the three months ended March 31, 2017 includes the effect of an impairment in the carrying value of our investment in T2 EF Cogen. As a result of the decrease in current and expected future utilization of the underlying cogeneration assets, we have determined that factors indicate that a decrease in the value of our investment has occurred that is other than temporary. As a result of this evaluation, we have recorded an impairment loss of approximately $12.0 million, which represents our proportionate share (50%) of an impairment charge recorded by the joint venture, as well as the impairment of the unamortized excess fair value resulting from the Atlas mergers.

The carrying values of the T2 gathering joint ventures include the effects of the Atlas mergers purchase accounting, which determined fair values for the joint ventures as of the date of acquisition. As of March 31, 2017, $30.1 million of unamortized excess fair value over the T2 Joint Ventures capital accounts remained. These basis differences, which are attributable to the underlying depreciable tangible gathering assets, are being amortized on a straight-line basis as components of equity earnings over the estimated 20 year useful lives of the underlying assets.

 

 

 

Note 9 — Accounts Payable and Accrued Liabilities

 

 

Accounts payable and accrued liabilities includes $27.2 million and $30.2 million of liabilities to creditors to whom we have issued checks that remain outstanding as of March 31, 2017 and December 31, 2016.

 

 

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Note 10 — 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 three months ended March 31, 2017:

 

 

Compliance with Debt Covenants

 

As of March 31, 2017, we were in compliance with the covenants contained in our various debt agreements.

 

Securitization Facility

 

On February 23, 2017, we amended the accounts receivable securitization facility (“Securitization Facility”) to increase the facility size from $275.0 million to $350.0 million.  As of March 31, 2017, there was $285.0 million outstanding under the Securitization Facility.

 

 

 

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Note 11 — Other Long-term Liabilities

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

 

 

Asset Retirement Obligations

Our ARO primarily relate to certain gas gathering pipelines and processing facilities. The changes in our ARO are as follows:

 

_____________________________________________________________________________________________________________________________________________________________

 

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 March 31, 2017.

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

 

 

Deferred Revenue

 

We have certain long-term contractual arrangements under which we have received consideration, but which require future performance by Targa. These arrangements result in deferred revenue, which will be recognized over the periods that performance will be provided.

 

Deferred revenue includes consideration received related to the construction and operation of a crude oil and condensate splitter. On December 27, 2015, Targa Terminals LLC and Noble Americas Corp., a subsidiary of Noble Group Ltd., entered into a long-term, fee-based agreement (“Splitter Agreement”) under which we will build and operate a 35,000 barrel per day crude oil and condensate splitter at our Channelview Terminal on the Houston Ship Channel (“Channelview Splitter”) and provide approximately 730,000 barrels of storage capacity. The Channelview Splitter will have the capability to split approximately 35,000 barrels per day of crude oil 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 project is expected to be completed by the first half of 2018, and has an estimated total cost of approximately $140.0 million. The first annual advance payment due under the Splitter Agreement was received in October 2016 and has been recorded as deferred revenue, as the Splitter Agreement requires future performance by Targa. Subsequent annual payments of $43.0 million (subject to an annual inflation factor) will be received

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through 2022. The deferred revenue will be recognized over the contractual period that future performance will be provided, currently anticipated to commence with start-up in 2018 and continuing through 2025.

 

Deferred revenue also includes consideration received in a 2015 amendment (the “gas contract amendment”) to a gas gathering and processing agreement. We measured the estimated fair value of the assets transferred to us using significant other observable inputs representative of a Level 2 fair value measurement.  Because the gas contract amendment will require future performance by Targa, we have recorded the consideration received as deferred revenue. The deferred revenue related to this amendment is being recognized on a straight-line basis through the end of the agreement’s term in 2030.

 

Deferred revenue also includes consideration received for other construction activities of facilities connected to our systems. The deferred revenue related to these other construction activities will be recognized over the periods that future performance will be provided, which extend through 2023.

 

 

The following table shows the components of deferred revenue:

 

 

The following table shows the changes in deferred revenue:

 

 

Contingent Consideration

 

A contingent consideration liability arising from potential earn-out payments in connection with the Permian Acquisition has been recognized at its preliminary fair value. We agreed to pay up to an additional $935.0 million in potential earn-out payments that may occur in 2018 and 2019. The first potential earn-out payment would occur in May 2018. The preliminary acquisition date fair value of the potential earn-out payments of $461.6 million was recorded within other long-term liabilities on our Consolidated Balance Sheets. Subsequent changes in the fair value of this liability, excluding any measurement period adjustments of the acquisition date fair value, are included in earnings. For the one month ended March 31, 2017, we had an increase in the fair value of this liability of $3.2 million, bringing the Permian Acquisition contingent consideration to $464.8 million as of March 31, 2017. See Note 17 – Fair Value Measurements for additional discussion of the fair value methodology.

 

 

 

Note 12 — Partnership Units and Related Matters

 

Distributions

As a result of the TRC/TRP Merger, TRC is entitled to receive all available Partnership distributions after payment of preferred distributions each quarter. We have discretion under the Third A&R Partnership Agreement as to whether to distribute all available cash for any period. See Note 1 – Organization and Operations.

The following details the distributions declared or paid by us during the three months ended March 31, 2017:

 

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Contributions

Subsequent to December 1, 2016, the effective date of the Third A&R Partnership Agreement, no units will be issued for capital contributions to us, but all capital contributions will continue to be allocated 98% to the limited partner and 2% to the general partner. During three months ended March 31, 2017, TRC made total capital contributions to us of $655.0 million.     

 

Preferred Units

 

In October 2015, we completed an offering of 5,000,000 Preferred Units at a price of $25.00 per unit.   The Preferred Units are listed on the NYSE under the symbol “NGLS PRA.”

 

Distributions on our 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%.

We paid $2.8 million of distributions to the holders of preferred units (“Preferred Unitholders”) during the three months ended March 31, 2017. The Preferred Units are reported as noncontrolling interests in our financial statements.  

 

Subsequent Event

 

In April 2017, the board of directors of our general partner declared a cash distribution of $0.1875 per Preferred Unit, resulting in approximately $0.9 million in distributions which will be paid on May 15, 2017.

 

Note 13 — 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 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 TPL derivative contracts with a fair value of $102.1 million as of February 27, 2015 (the “acquisition date”), were novated to us and included in the acquisition date fair value of assets acquired. We received derivative settlements of $3.0 million for the three months ended March 31, 2017 and $8.7 million for the three months ended March 31, 2016, related to these novated contracts. From the acquisition date through March 31, 2017, we have received derivative settlements of $97.6 million. The remainder of the novated contracts will settle by the end of 2017. These settlements were reflected as a reduction of the acquisition date fair value of the TPL 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, we recorded ineffectiveness losses of less than $0.1 million for the three months ended March 31, 2016, related to otherwise qualifying TPL derivatives, which are primarily natural gas swaps. There were no ineffectiveness losses on these derivatives for the three months ended March 31, 2017.

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. 

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At March 31, 2017, the notional volumes of our commodity derivative contracts were:

 

 

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:

 

 

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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 TRP Revolver that ranks equal in right of payment with liens granted in favor of our senior secured lenders. Some of our hedges are futures contracts executed through a broker that clears the hedges through an exchange. We maintain a margin deposit with the broker in an amount sufficient enough to cover the fair value of our open futures positions. The margin deposit is considered collateral, which is located within other current assets on our Consolidated Balance Sheets and is not offset against the fair values of our derivative instruments.

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 $15.4 million as of March 31, 2017. 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 margined daily and do not require any credit adjustment.

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

 

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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.

 

 

Based on valuations as of March 31, 2017, we expect to reclassify commodity hedge related deferred gains of $10.8 million included in accumulated other comprehensive income into earnings before income taxes through the end of 2019, with $2.6 million of losses to be reclassified over the next twelve months.

 

See Note 14 – Fair Value Measurements for additional disclosures related to derivative instruments and hedging activities.

 

 

Note 14 — 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.

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 March 31, 2017, a net asset position of $15.4 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 $47.5 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 $79.0 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:

Contingent consideration liabilities related to business acquisitions are carried at fair value.

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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:

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.

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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 March 31, 2017, we had 17 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 Permian Acquisition contingent consideration was determined using a Monte-Carlo simulation model. Significant inputs used in the fair value measurement include expected gross margin (calculated in accordance with the terms of the purchase and sale agreements), term of the earn-out period, risk adjusted discount rate and volatility associated with the underlying assets. A significant decrease in expected gross margin during the earn-out period, or significant increase in the discount rate or volatility would result in a lower fair value estimate.  The fair value of the TPL contingent consideration was determined using a probability-based model measuring the likelihood of meeting certain volumetric measures. The inputs for both models are not observable; therefore, the entire valuations of the contingent considerations are categorized in Level 3. Changes in the fair value of these liabilities are included in Other income (expense) on the Consolidated Statements of Operations.

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

 

 

 

 

Note 15 — 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.

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

_______________________

 

 

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Note 16 – Contingencies

Legal Proceedings

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 by Versado Gas Processors, L.L.C., which was a joint venture in which we owned a 63% interest until October 31, 2016, when we acquired the remaining 37% membership interest from Chevron U.S.A Inc. On January 31, 2017, Targa Midstream Services LLC executed a settlement agreement with the New Mexico Environment Department which resolved the matter for a civil penalty in the amount of $29,223.

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

 

Note 17 – Other Operating (Income) Expense

 

Other operating (income) expense is comprised of the following:

 

 

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Note 18 — Supplemental Cash Flow Information

 

_____________

 

 

 

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Note 19 — Segment Information

 

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

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.

Logistics and Marketing operations are generally connected to and supplied in part by our Gathering and Processing segment 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:

 

 

 

 

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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, 2016 (“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 (“we,” “our,” the “Partnership” or “TRP”) is a Delaware limited partnership formed in October 2006 by Targa Resources Corp. (“TRC” or “Targa”). Our common units were listed on the NYSE under the symbol “NGLS” prior to TRC’s acquisition on February 17, 2016 of all 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.”

 

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 our outstanding common units.

 

Our Operations

 

We are engaged in the business of:

 

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

 

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, fractionating, terminaling, transporting and marketing of NGLs and NGL products, including services to LPG exporters; storing and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our other businesses.

 

Logistics and Marketing operations are generally connected to and supplied in part by our Gathering and Processing segment 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 that are included in operating margin.

 

 

 

 

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Recent Developments

Gathering and Processing Segment Expansion

 

Permian Acquisition

 

On March 1, 2017, we completed the purchase of 100% of the membership interests of Outrigger Delaware Operating, LLC, Outrigger Southern Delaware Operating, LLC (together “New Delaware”) and Outrigger Midland Operating, LLC (“New Midland” and together with New Delaware, the “Permian Acquisition”).

 

We paid $484.1 million in cash at closing on March 1, 2017, and will pay $90.0 million within 90 days of closing (collectively, the "initial purchase price"). Contributions from TRC were used to fund the cash portion of the Permian Acquisition purchase price. Subject to certain performance-linked measures and other conditions, additional cash of up to $935.0 million may be payable to the sellers of New Delaware and New Midland in potential earn-out payments that may occur in 2018 and 2019. The potential earn-out payments will be based upon a multiple of realized gross margin from contracts that existed on March 1, 2017.

 

New Delaware's gas gathering and processing and crude gathering assets are located in Loving, Winkler, Pecos and Ward counties. The operations are backed by producer dedications of more than 145,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 14 years. The New Delaware assets include 70 MMcf/d of processing capacity and an uninstalled 60 MMcf/d plant, which we are in the process of installing in the Delaware Basin with expectations of commencing operations in late 2017. Currently, there is 40,000 Bbl/d of crude gathering capacity on the New Delaware system.

 

New Midland's gas gathering and processing and crude gathering assets are located in Howard, Martin and Borden counties. The operations are backed by producer dedications of more than 105,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 13 years. The New Midland assets include 10 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the New Midland system.

 

New Delaware's gas gathering and processing assets were connected to our Sand Hills system in the first quarter of 2017, and we expect that New Midland's gas gathering and processing assets will be connected to our existing WestTX system during 2017. We believe connecting the acquired assets to our legacy Permian footprint creates operational and capital synergies, and will afford enhanced flexibility in serving our producer customers.

 

Additional Permian System Processing Capacity

 

In November 2016, we announced plans to restart the idled 45 MMcf/d Benedum cryogenic processing plant and to add 20 MMcf/d of capacity at our Midkiff plant in our WestTX system.  The Benedum plant was idled in September 2014 after the start-up of the 200 MMcf/d Edward plant, and was brought back online in the first quarter of 2017.  We expect that the addition of 20 MMcf/d of capacity at our Midkiff plant will increase overall plant capacity of the Midkiff/Consolidator plant complex in Reagan County, Texas from 210 MMcf/d to 230 MMcf/d. The Midkiff/Consolidator plant complex addition is expected to be completed in the second quarter of 2017. Also in November 2016, we announced plans to build the 200 MMcf/d Joyce plant, which is expected to be completed in the first quarter of 2018. We expect total net growth capital expenditures for the Joyce plant to be approximately $90 million.

 

In May 2017, we announced plans to build a new plant and expand the gathering footprint of our Permian Midland system in the Midland Basin. This project includes a new 200 MMcf/d cryogenic processing plant, known as the Johnson plant, which is expected to begin operations in the third quarter of 2018. We expect total net growth capital expenditures for the Johnson plant to be approximately $90 million.

 

Also in May 2017, we announced plans to build a new plant and expand the gathering footprint of our Permian Delaware system in the Delaware Basin. This project includes a new 250 MMcf/d cryogenic processing plant, known as the Wildcat plant, which is expected to begin operations in the third quarter of 2018. We expect total net growth capital expenditures for the Wildcat plant to be approximately $130 million.

 

Eagle Ford Shale Natural Gas Gathering and Processing Joint Ventures

 

In October 2015, we announced that we had entered into the Carnero Joint Ventures with Sanchez Energy Corporation (“Sanchez”) to construct the 200 MMcf/d Raptor Plant and approximately 45 miles of associated pipelines. In July 2016,

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Sanchez sold its interest in the gathering joint venture to Sanchez Production Partners, L.P. (“SPP”) and in November 2016, sold its interest in the processing joint venture to SPP. Through the Carnero Joint Ventures, we indirectly own a 50% interest in the plant and the approximately 45 miles of high pressure gathering pipelines that will connect SPP's Catarina gathering system to the plant. We hold the capacity on the high pressure gathering pipelines, and pay the gathering joint venture fees for transportation.

 

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 pipelines are supported by long-term, firm, fee-based contracts and acreage dedications with Sanchez. We manage operations of the high pressure gathering lines and the plant, which is expected to begin operations in the second quarter of 2017, and will be capable of processing 200 MMcf/d. In February 2017, we announced the addition of compression to increase the processing capacity of the Raptor Plant to 260 MMcf/d, which we expect to be completed in the third quarter of 2017. Prior to the plant being placed in service, we benefited from Sanchez natural gas volumes that were processed at our Silver Oak facilities in Bee County, Texas.

 

Badlands

 

During 2017, we expect to invest approximately $150 million to expand our crude gathering and natural gas processing business in the Williston Basin, North Dakota. The expansion includes the addition of pipelines, LACT units, compression and other infrastructure to support continued growth in producer activity.

 

Sale of Venice Gathering System, L.L.C.

 

Through our 76.8% ownership interest in Venice Energy Services Company, L.L.C. (“VESCO”), we have operated the Venice gas plant and the Venice gathering system. On April 4, 2017, VESCO entered into a purchase and sale agreement with Rosefield Pipeline Company, LLC, an affiliate of Arena Energy, LP, to sell its 100% ownership interests in Venice Gathering System, L.L.C. (“VGS”), a Delaware limited liability company engaged in the business of transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”), for approximately $0.4 million in cash. Additionally, the VGS asset retirement obligations were assumed by the buyer. VGS owns and operates a natural gas gathering system in the Gulf of Mexico. Historically, VGS has been reported in our Gas Gathering and Processing segment. After the sale of VGS, we continue to operate the Venice gas plant through our ownership in VESCO. Targa Midstream Services LLC will continue to operate the Venice gathering system for up to four months after closing pursuant to a Transition Services Agreement with VGS.

 

In addition to the major projects noted above, we have other growth capital expenditures in 2017 related to the continued build out of our gathering and processing infrastructure and logistics capabilities. 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

 

On February 23, 2017, we amended our account receivable securitization facility (“Securitization Facility”) to increase the facility size to $350.0 million from $275.0 million. 

 

 

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see “Recent Accounting Pronouncements” included within Note 3 – Significant Accounting Policies in our Consolidated Financial Statements.

 

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.

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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, 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.

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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 (loss) 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 mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015; non-cash compensation on equity grants; transaction costs related to business acquisitions; the Splitter Agreement adjustment; earnings/losses from unconsolidated affiliates net of distributions, distributions from preferred interests, change in contingent consideration and the noncontrolling interest portion of depreciation and amortization expense. 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.

 

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Our Non-GAAP Financial Measures

 

The following tables reconcile the non-GAAP financial measures used by management to the most directly comparable GAAP measures for the periods indicated.

 

 

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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 March 31, 2017 Compared to Three Months Ended March 31, 2016

 

The increase in commodity sales was primarily due to higher commodity prices ($757.8 million), partially offset by decreased volumes ($45.4 million) and the impact of hedge settlements ($25.3 million). Additionally, fee-based and other revenues decreased primarily due to lower export fees.

 

The increase in product purchases was primarily due to the impact of higher commodity prices, partially offset by decreased volumes.

 

The higher operating margin and gross margin in 2017 reflects increased segment margin results for Gathering and Processing, partially offset by decreased Logistics and Marketing segment margins. Operating expenses increased compared to 2016 due to higher

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maintenance in the Logistics and Marketing segment and plant and system expansions in the Permian region. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.

 

The decrease in depreciation and amortization expenses reflects the impact of fully depreciated property assets and lower scheduled amortization on the Badlands intangibles, partially offset by one month of operations of the Permian Acquisition in 2017 and the impact of growth investments, primarily CBF Train 5 which went into service in June 2016.

 

General and administrative expenses increased primarily due to higher compensation and benefits.

 

We recognized an impairment of goodwill in the first quarter of 2016 of $24.0 million to finalize the 2015 provisional impairment of goodwill. The impairment charge related to goodwill acquired in the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively, the “Atlas mergers”).

 

Other operating (income) expense in 2017 includes the loss due to the reduction in the carrying value of our ownership interest in the Venice Gathering System in connection with the April 4, 2017 sale.

 

Net interest expense increased primarily due to higher non-cash interest expense related to the mandatorily redeemable preferred interests liability that is revalued quarterly at its estimated redemption value as of the reporting date. The estimated redemption value of the mandatorily redeemable preferred interests increased in 2017, whereas it decreased in 2016. This increase was partially offset by the impact of lower average outstanding borrowings during 2017.

 

Higher equity losses in 2017 reflects a $12.0 million loss provision due to the impairment of our investment in the T2 EF Cogen joint venture, partially offset by increased equity earnings at Gulf Coast Fractionators.

 

During 2016, we recorded a gain of $24.7 million on open debt market repurchases and other financing activities. There were no repurchases or redemptions of our long-term debt in 2017.

 

Other expense in 2017 was primarily attributable to $5.1 million of non-recurring transaction costs related to the Permian Acquisition and a $3.2 million increase in the fair value of the Permian Acquisition contingent consideration liability from the acquisition date to March 31, 2017.

 

The increase in income tax benefit was primarily due to a Texas Margin Tax refund in the first quarter of 2017.

 

Net income attributable to noncontrolling interests increased primarily due to our October 2016 acquisition of the 37% interest of Versado that we did not already own and higher earnings 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 March 31, 2017 Compared to Three Months Ended March 31, 2016

 

The increase in gross margin was primarily due to higher commodity prices and the inclusion of the Permian Acquisition for one month in 2017 partially offset by lower throughput volumes. Inlet volumes for Field Gathering and Processing were slightly lower with increases at WestTX, SAOU and Versado offset by decreases at the other areas. The inlet volume decrease for Coastal Gathering and Processing which generates significantly lower margins than does Field Gathering and Processing, accounted for over 67% of the overall inlet volume decrease. Despite overall lower inlet volumes, NGL production and NGL sales increased primarily due to increased plant recoveries including additional ethane recovery. Natural gas sales decreased due to lower inlet volumes and increased ethane recovery. Total crude oil gathered volumes increased in the Permian region due to the Permian Acquisition and in Badlands due to system expansions. Badlands natural gas volumes decreased primarily due to severe winter weather.

 

The increase in operating expenses was primarily driven by plant and system expansions in the Permian region and the inclusion of the Permian Acquisition for one month of 2017.  Operating expenses in other areas were relatively flat.

 

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 Field portion of the Gathering and Processing segment:

 

 

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Logistics and Marketing Segment

 

________________________________________________________

 

Three Months Ended March 31, 2017 Compared to Three Months Ended March 31, 2016

 

Logistics and Marketing gross margin decreased due to lower LPG export margin and lower wholesale and marketing margin, partially offset by higher fractionation margin, higher terminaling and storage throughput and higher treating margin. LPG export margin decreased due to lower fees partially offset by higher volumes. Wholesale and marketing margin decreased primarily due to less favorable wholesale supply opportunities in 2017 compared to the same period last year and lower marketing gains. Fractionation margin increased due to higher system product gains, higher fees and higher supply volume. Fractionation margin was partially impacted by the variable effects of fuel and power which are largely reflected in operating expenses (see footnote (2) above). Treating margin increased slightly due to higher volumes partially offset by lower fees.

 

Operating expenses increased due to higher maintenance primarily associated with unusual one-time events, higher fuel and power, and higher compensation and benefits.

 

Other

 

 

Other contains the results (including any hedge ineffectiveness) of commodity derivative activities related to Gathering and Processing hedges of equity volumes that are included in operating margin and mark-to-market gain/losses related to derivative contracts that were not designated as cash flow hedges. 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 entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas, NGL and condensate equity volumes in our Gathering and Processing Operations that result from percent of proceeds/liquids processing arrangements. Because we are essentially forward-selling a portion of our future plant equity volumes, these hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices.

 

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

 

 

 

As part of the Atlas mergers, outstanding TPL derivative contracts with a fair value of $102.1 million as of February 27, 2015 (the “acquisition date”), were novated to us and included in the acquisition date fair value of assets acquired. We received derivative settlements of $3.0 million for the three months ended March 31, 2017 and $8.7 million for the three months ended March 31, 2016, related to these novated contracts. From the acquisition date through March 31, 2017, we have received total derivative settlements of $97.6 million. The remainder of the novated contracts will settle by the end of 2017. These settlements were reflected as a reduction of the acquisition date fair value of the TPL derivative assets acquired and had no effect on results of operations.

 

 

Liquidity and Capital Resources

As of March 31, 2017, we had $71.7 million of “Cash and cash equivalents,” on our Consolidated Balance Sheet. We believe our cash position, remaining borrowing capacity on our credit facilities (discussed below in “Short-term Liquidity”), and our cash flows from operating activities are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below.

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 commodity prices, weather 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 the TRP Revolver, borrowings under the 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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Short-term Liquidity

Our short-term liquidity as of May 1, 2017, was:

 

 

Other potential capital resources associated with our existing arrangements include:

A portion of our capital resources are 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.

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 that are 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 $197.3 million from December 31, 2016 to March 31, 2017.  The major items contributing to this decrease were the establishment of the $90 million purchase consideration payable related to the Permian Acquisition, reduction in inventory due to higher export volumes and the seasonality of our wholesale business, a decrease in our net commodity receivables and payables due to lower commodity revenue in March 2017 as compared with December 2016 and reduced commodity purchases partially offset by an increase in our net risk management working capital position due to changes in the forward prices of commodities and a higher cash balance. The increase of $260.5 million in current debt obligations was due to reclassification of the senior note due January 2018 from long-term to current, as well as the increased receivables available for the Securitization Facility.

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.

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Long-term Financing

Long-term financing consists of long-term debt obligations and preferred units.

From time to time, we issue long-term debt securities, which we refer to as senior notes. Our senior notes issued to date, generally have similar terms other than interest rates, maturity dates and redemption premiums. All of our fixed rate senior notes provide that the notes may be redeemed at any time at a price equal to 100% plus accrued interest to the redemption date, and in some cases, a make-whole premium. As of March 31, 2017 and December 31, 2016, the aggregate principal amount outstanding of our various long-term debt obligations (excluding current maturities) was $3,806.3 million and $4,206.8 million, respectively.

The majority of our long-term debt is fixed rate borrowings; however, we have some exposure to the risk of changes in interest rates, primarily as a result of the variable rate borrowings under the TRP Revolver. We may enter into interest rate hedges with the intent to mitigate the impact of changes in interest rates on cash flows. As of March 31, 2017, we do not have any interest rate hedges.

To date, we do not believe our debt balances have adversely affected our operations, our ability to grow or our ability to repay or refinance our indebtedness. For additional information about our debt-related transactions, see Note 10 - Debt Obligations to our consolidated financial statements.  For information about our interest rate risk, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

 

In October 2015, we completed an offering of 5,000,000 Preferred Units at a price of $25.00 per unit. We received net proceeds after costs of approximately $121.1 million. The Preferred Units are listed on the NYSE under the symbol “NGLS PRA.” 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%. 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.

 

Compliance with Debt Covenants

As of March 31, 2017, we were in compliance with the covenants contained in our various debt agreements.

 

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.

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

 

 

Higher commodity prices were the primary contributor to increased cash collections and payments for product purchases in 2017 compared to 2016. Derivative settlements remained an overall source of revenue during 2017, but at a lower amount as commodity price spreads between the prices paid to counterparties and the fixed prices we received on those derivative contracts were lower in 2017 in comparison to 2016. Interest payments are lower this year largely due to repurchases of debt in the first quarter 2016, offset by the timing of payments of interest on two new series of notes we issued in 2016. Cash payments for general and administrative expenses and operating expenses were higher, primarily due to increases in compensation and benefits, contractor and other professional services, coupled with higher utilities and higher maintenance. Other cash payments in 2017 were higher mainly due to transaction expenses associated with the Permian Acquisition in 2017.

Cash Flows from Investing Activities

 

 

Cash used in investing activities increased in 2017 compared to 2016, primarily due to the $480.8 million outlay for the cash portion due at closing of the Permian Acquisition consideration. An additional $90 million will be paid during the second quarter of 2017, as well as potential contingent consideration payments in 2018 and 2019. Growth and maintenance capital expenditures decreased $45.9 million during 2017 reflecting the completion of major growth projects during 2016.

Cash Flows from Financing Activities

 

 

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In 2017, we realized a net source of cash from financing activities, primarily due to contributions from TRC, partially offset by payments of distributions to TRC and repayments of our credit facilities.

 

In 2016, we incurred a net use of cash from financing activities, primarily due to a net reduction of debt outstanding and payment of distributions to TRC, offset by contributions from TRC and our general partner. With the contributions from TRC, we repurchased a portion of our senior notes through open market repurchases generally at a discount to par values and repaid a portion of the outstanding borrowings under the TRP Revolver.

 

 

Distributions

As a result of the TRC/TRP Merger, TRC is entitled to receive all available Partnership distributions after payment of preferred distributions each quarter. We have discretion under the Third A&R Partnership Agreement, as to whether to distribute all available cash for any period. See Note 1 – Organization and Operations of the “Consolidated Financial Statements” included in this quarterly report.

 

The following table details the distributions declared and/or paid by us during the three months ended March 31, 2017.

 

Preferred Units

 

Distributions on our Preferred Units are declared and paid monthly. As of March 31, 2017, we have 5,000,000 Preferred Units outstanding. For the three months ended March 31, 2017 $2.8 million of distributions were paid. We have accrued distributions to Series A Preferred Unitholders of $0.9 million for March, which were paid subsequently on April 17, 2017.

 

In April 2017, the board of directors of our general partner declared a cash distribution of $0.1875 per Preferred Unit. This distribution will be paid on May 15, 2017.

Capital Requirements

Our capital requirements relate to capital expenditures, which are classified as expansion expenditures including business acquisitions and 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.

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We currently estimate that we will invest at least $960 million in net growth capital expenditures (exclusive of outlays for business acquisitions) for announced projects in 2017. 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 in the first quarter of 2017 as compared to 2016, primarily due to lower CBF train 5 construction costs, partially offset by the restart of the Benedum Plant and the commencement of construction of the Joyce Plant. Our maintenance capital expenditures increased for 2017 as compared to 2016, primarily due to higher numbers of compressors reaching the end of their maintenance cycles in the first quarter 2017 versus 2016 and increased well connects.

Off-Balance Sheet Arrangements

As of March 31, 2017, there were $38.8 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.

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

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

Risk Management

We evaluate counterparty risks related to our commodity derivative contracts and trade credit. We have all our commodity derivatives with major financial institutions or major oil companies. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of operations. We sell our natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.

Crude oil, NGL and natural gas prices are also volatile. In an effort to reduce the variability of our cash flows, we have entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas equity volumes, NGL equity volumes and condensate equity volumes and future commodity purchases and sales through 2019. The current market conditions may also impact our ability to enter into future commodity derivative contracts.

Commodity Price Risk

A significant portion of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the proceeds from the sale of natural gas and/or NGLs 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 our 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 March 31, 2017, we have hedged the commodity price associated with a portion of our expected (i) natural gas equity volumes in our Gathering and Processing operations, (ii) NGL and condensate equity volumes in our Gathering and Processing operations that result from our percent-of-proceeds processing arrangements and (iii) future commodity purchases and sales in our Logistics and Marketing segment 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

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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 entering into derivative transactions using swaps, collars, purchased puts (or floors), futures 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, which 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 the Partnership’s senior secured indebtedness that ranks equal in right of payment with liens granted in favor of the Partnership’s 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 on futures exchanges.

Our operating revenues increased (decreased) by net hedge adjustments on commodity derivative contracts of $(6.7) million and $21.2 million, during the three months ended March 31, 2017 and 2016, as a result of transactions accounted for as derivatives. We account for derivatives designated as hedges that mitigate commodity price risk as cash flow hedges. Changes in fair value are deferred in other comprehensive income until the underlying hedged transactions settle. 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 risk management position has moved from a net liability position of $53.3 million at December 31, 2016 to a net asset position of $15.4 million at March 31, 2017. The fixed prices we currently expect to receive on derivative contracts are above the aggregate forward prices for commodities related to those contracts, creating this net asset position.

50

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As of March 31, 2017, we had the following derivative instruments that will settle during the years shown below:

Natural GAS

 

 

51

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NGLs

 

52

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CONDENSATE

 

 

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 contract, the valuations are classified as Level 3 within the fair value hierarchy. See Note 14 - 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 March 31, 2017, we do not have any interest rate hedges. However, we may enter into interest rate hedges in the future with the intent 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 March 31, 2017, we had $285.0 million in outstanding variable rate borrowings under the TRP Revolver and 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 $2.9 million.

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 margined daily. Should the creditworthiness of one or more of the counterparties decline, our ability to mitigate nonperformance risk is limited to a

53

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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 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 $30.1 million as of March 31, 2017. The range of losses attributable to our individual counterparties would be between $0.1 million and $13.3 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 as of March 31, 2017, our operating income would decrease by $5.4 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 such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.

 

Changes in Internal Control Over Financial Reporting 

There have been no changes in our internal control over financial reporting that occurred during the quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

54

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings.

 

The information required for this item is provided in Note 16 – 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 Annual Report. All of these risks and uncertainties could adversely affect our business, financial condition and/or results of operations.

 

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

 

Recent Sales of Unregistered Securities.

 

Not applicable.

 

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.

55

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Item 6. Exhibits.

 

56

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57

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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.

 

 

 

58

Exhibit 4.2

 

#5416445.4

 

SUPPLEMENTAL INDENTURE

 

 

Supplemental Indenture (this “Supplemental Indenture”), dated as of March 10, 2017, among Targa SouthOk NGL Pipeline LLC, an Oklahoma limited liability company (the “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 Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary 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 Subsidiary 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. The 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 the Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the 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 Subsidiary 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 SUBSIDIARY

 

Targa SouthOk NGL Pipeline LLC

 

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

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

---

 

TRUSTEE

 

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

 

 

By: /s/ Shazia Flores

Authorized Signatory

 

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

Exhibit 4.3

#5416449.4

 

SUPPLEMENTAL INDENTURE

 

 

Supplemental Indenture (this “Supplemental Indenture”), dated as of March 10, 2017, among Targa SouthOk NGL Pipeline LLC, an Oklahoma limited liability company (the “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 Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary 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 Subsidiary 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. The 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 the Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the 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 Subsidiary 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 SUBSIDIARY

 

Targa SouthOk NGL Pipeline LLC

 

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

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

---

 

TRUSTEE

 

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

 

 

By:  /s Shazia Flores

Authorized Signatory

 

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

Exhibit 4.4

 

#5416502.4

 

SUPPLEMENTAL INDENTURE

 

 

Supplemental Indenture (this “Supplemental Indenture”), dated as of March 10, 2017, among Targa SouthOk NGL Pipeline LLC, an Oklahoma limited liability company (the “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 Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary 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 Subsidiary 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. The 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 the Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the 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 Subsidiary 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 SUBSIDIARY

 

Targa SouthOk NGL Pipeline LLC

 

 

 

By: /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

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 4.5

 

#5416503.4

 

SUPPLEMENTAL INDENTURE

 

 

Supplemental Indenture (this “Supplemental Indenture”), dated as of March 10, 2017, among Targa SouthOk NGL Pipeline LLC, an Oklahoma limited liability company (the “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 Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary 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 Subsidiary 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. The 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 the Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the 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 Subsidiary 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 SUBSIDIARY

 

Targa SouthOk NGL Pipeline LLC

 

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

 

 

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

Exhibit 4.6

 

#5416507.4

 

SUPPLEMENTAL INDENTURE

 

 

Supplemental Indenture (this “Supplemental Indenture”), dated as of March 10, 2017, among Targa SouthOk NGL Pipeline LLC, an Oklahoma limited liability company (the “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 Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary 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 Subsidiary 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. The 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 the Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the 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 Subsidiary 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 SUBSIDIARY

 

Targa SouthOk NGL Pipeline LLC

 

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

 

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

Exhibit 4.7

 

#5416513.4

 

SUPPLEMENTAL INDENTURE

 

 

Supplemental Indenture (this “Supplemental Indenture”), dated as of March 10, 2017, among Targa SouthOk NGL Pipeline LLC, an Oklahoma limited liability company (the “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 Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary 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 Subsidiary 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. The 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 the Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the 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.

 

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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 Subsidiary 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 SUBSIDIARY

 

Targa SouthOk NGL Pipeline LLC

 

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

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 4.8

 

#5416515.4

 

SUPPLEMENTAL INDENTURE

 

 

Supplemental Indenture (this “Supplemental Indenture”), dated as of March 10, 2017, among Targa SouthOk NGL Pipeline LLC, an Oklahoma limited liability company (the “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 Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary 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 Subsidiary 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. The 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 the Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the 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.

 

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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 Subsidiary 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 SUBSIDIARY

 

Targa SouthOk NGL Pipeline LLC

 

 

 

By:  /s/ Chris McEwan

Name: Chris McEwan

Title: Vice President and Treasurer

 

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: May 4, 2017

 

 

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: May 4, 2017

 

 

 

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 March 31, 2017 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: May 4, 2017

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 March 31, 2017 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: May 4, 2017

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.