UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2017

OR

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

For the transition period from            to           

Commission File Number: 001-33303

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)

 

Delaware

 

65-1295427

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer Identification No.)

 

 

 

1000 Louisiana St, Suite 4300, Houston, Texas

 

77002

(Address of principal executive offices)

 

(Zip Code)

 

(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.

 

Large accelerated filer

 

Accelerated filer

Non-accelerated filer

(Do not check if a smaller reporting company)

Smaller reporting company

 

 

 

Emerging growth company

 

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.

 

 

 

 

 

 


TABLE OF CONTENTS

 

PART I—FINANCIAL INFORMATION

 

 

 

 

 

Item 1. Financial Statements

 

4

 

 

 

Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016

 

4

 

 

 

Consolidated Statements of Operations for the three months ended March 31, 2017 and 2016

 

5

 

 

 

Consolidated Statements of Comprehensive Income (Loss) for the three months ended March 31, 2017 and 2016

 

6

 

 

 

Consolidated Statements of Changes in Owners' Equity for the three months ended March 31, 2017

 

7

 

 

 

Consolidated Statements of Cash Flows for the three months ended March 31, 2017 and 2016

 

8

 

 

 

Notes to Consolidated Financial Statements

 

9

 

 

 

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

 

32

 

 

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

 

49

 

 

 

Item 4. Controls and Procedures

 

54

 

 

 

PART II—OTHER INFORMATION

 

 

 

 

 

Item 1. Legal Proceedings

 

55

 

 

 

Item 1A. Risk Factors

 

55

 

 

 

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

 

55

 

 

 

Item 3. Defaults Upon Senior Securities

 

55

 

 

 

Item 4. Mine Safety Disclosures

 

55

 

 

 

Item 5. Other Information

 

55

 

 

 

Item 6. Exhibits

 

56

 

 

 

SIGNATURES

 

 

 

 

 

Signatures

 

58

 


 

1


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:

 

 

the timing and extent of changes in natural gas, natural gas liquids, crude oil and other commodity prices, interest rates and demand for our services;

 

 

the level and success of crude oil and natural gas drilling around our assets, our success in connecting natural gas supplies to our gathering and processing systems, oil supplies to our gathering systems and natural gas liquid supplies to our logistics and marketing facilities and our success in connecting our facilities to transportation services and markets;

 

 

our ability to access the capital markets, which will depend on general market conditions and the credit ratings for our debt obligations;

 

 

the amount of collateral required to be posted from time to time in our transactions;

 

 

our success in risk management activities, including the use of derivative instruments to hedge commodity price risks;

 

 

the level of creditworthiness of counterparties to various transactions with us;

 

 

changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment;

 

 

weather and other natural phenomena;

 

 

industry changes, including the impact of consolidations and changes in competition;

 

 

our ability to obtain necessary licenses, permits and other approvals;

 

 

our ability to grow through acquisitions or internal growth projects and the successful integration and future performance of such assets;

 

 

general economic, market and business conditions; and

 

 

the risks described in our Annual Report on Form 10-K for the year ended December 31, 2016 (“Annual Report”) and our reports and registration statements filed from time to time with the United States Securities and Exchange Commission (“SEC”).

 

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.

 

 

 

2


 

 

 

 

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

 

Bbl

Barrels (equal to 42 U.S. gallons)

BBtu

Billion British thermal units

Bcf

Billion cubic feet

Btu

British thermal units, a measure of heating value

/d

Per day

GAAP

Accounting principles generally accepted in the United States of America

gal

U.S. gallons

GPM

Liquid volume equivalent expressed as gallons per 1000 cu. ft. of natural gas

LACT

Lease Automatic Custody Transfer

LIBOR

London Interbank Offered Rate

LPG

Liquefied petroleum gas

MBbl

Thousand barrels

MMBbl

Million barrels

MMBtu

Million British thermal units

MMcf

Million cubic feet

MMgal

Million U.S. gallons

NGL(s)

Natural gas liquid(s)

NYMEX

New York Mercantile Exchange

NYSE

New York Stock Exchange

 

 

 

 

Price Index Definitions

 

C2-OPIS-MB

Ethane, Oil Price Information Service, Mont Belvieu, Texas

C3-OPIS-MB

Propane, Oil Price Information Service, Mont Belvieu, Texas

C5-OPIS-MB

Natural Gasoline, Oil Price Information Service, Mont Belvieu, Texas

EP-PERMIAN

Inside FERC Gas Market Report, El Paso (Permian Basin)

IC4-OPIS-MB

Iso-Butane, Oil Price Information Service, Mont Belvieu, Texas

IF-PB

Inside FERC Gas Market Report, Permian Basin

IF-PEPL

Inside FERC Gas Market Report, Oklahoma Panhandle, Texas-Oklahoma Midpoint

IF-WAHA

Inside FERC Gas Market Report, West Texas WAHA

NC4-OPIS-MB

Normal Butane, Oil Price Information Service, Mont Belvieu, Texas

NG-NYMEX

NYMEX, Natural Gas

WTI-NYMEX

NYMEX, West Texas Intermediate Crude Oil

 

 

3


 

PART I – FINANC IAL INFORMATION

Item 1. Financial Statements.

TARGA RESOURCES PARTNERS LP

CONSOLIDATED BALANCE SHEETS

 

 

 

March 31,

 

 

December 31,

 

 

 

2017

 

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

(Unaudited)

 

 

 

(In millions)

 

ASSETS

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

71.7

 

 

$

68.0

 

Trade receivables, net of allowances of $0.1 and $0.9 million at March 31, 2017 and December 31, 2016

 

 

536.1

 

 

 

673.2

 

Inventories

 

 

75.5

 

 

 

137.7

 

Assets from risk management activities

 

 

23.9

 

 

 

16.8

 

Other current assets

 

 

26.9

 

 

 

31.5

 

Total current assets

 

 

734.1

 

 

 

927.2

 

Property, plant and equipment

 

 

12,950.2

 

 

 

12,511.9

 

Accumulated depreciation

 

 

(2,986.8

)

 

 

(2,821.0

)

Property, plant and equipment, net

 

 

9,963.4

 

 

 

9,690.9

 

Intangible assets, net

 

 

2,238.8

 

 

 

1,654.0

 

Goodwill, net

 

 

369.0

 

 

 

210.0

 

Long-term assets from risk management activities

 

 

21.6

 

 

 

5.1

 

Investments in unconsolidated affiliates

 

 

227.0

 

 

 

240.8

 

Other long-term assets

 

 

15.9

 

 

 

16.9

 

Total assets

 

$

13,569.8

 

 

$

12,744.9

 

 

 

 

 

 

 

 

 

 

LIABILITIES AND OWNERS' EQUITY

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

819.5

 

 

$

773.9

 

Accounts payable to Targa Resources Corp.

 

 

46.5

 

 

 

61.0

 

Liabilities from risk management activities

 

 

22.2

 

 

 

49.1

 

Current maturities of debt

 

 

534.9

 

 

 

275.0

 

Total current liabilities

 

 

1,423.1

 

 

 

1,159.0

 

Long-term debt

 

 

3,778.3

 

 

 

4,177.0

 

Long-term liabilities from risk management activities

 

 

7.9

 

 

 

26.1

 

Deferred income taxes, net

 

 

26.4

 

 

 

26.9

 

Other long-term liabilities

 

 

676.4

 

 

 

205.3

 

 

 

 

 

 

 

 

 

 

Contingencies (see Note 16)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Owners' equity:

 

 

 

 

 

 

 

 

Series A preferred limited partners

Issued

 

 

Outstanding

 

 

 

 

120.6

 

 

 

120.6

 

March 31, 2017

 

5,000,000

 

 

 

5,000,000

 

 

 

 

 

 

 

 

 

 

December 31, 2016

 

5,000,000

 

 

 

5,000,000

 

 

 

 

 

 

 

 

 

 

Common limited partners

Issued

 

 

Outstanding

 

 

 

 

6,360.9

 

 

 

5,939.9

 

March 31, 2017

 

275,168,410

 

 

 

275,168,410

 

 

 

 

 

 

 

 

 

 

December 31, 2016

 

275,168,410

 

 

 

275,168,410

 

 

 

 

 

 

 

 

 

 

General partner

Issued

 

 

Outstanding

 

 

 

 

805.3

 

 

 

796.7

 

March 31, 2017

 

5,629,136

 

 

 

5,629,136

 

 

 

 

 

 

 

 

 

 

December 31, 2016

 

5,629,136

 

 

 

5,629,136

 

 

 

 

 

 

 

 

 

 

Accumulated other comprehensive income (loss)

 

 

 

 

 

10.5

 

 

 

(61.8

)

 

 

 

7,297.3

 

 

 

6,795.4

 

Noncontrolling interests in subsidiaries

 

 

 

 

 

360.4

 

 

 

355.2

 

Total owners' equity

 

 

7,657.7

 

 

 

7,150.6

 

Total liabilities and owners' equity

 

$

13,569.8

 

 

$

12,744.9

 

 

 

 

 

 

 

 

 

 

See notes to consolidated financial statements.

 

 

 

 

4


 

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

 

 

Three Months Ended March 31,

 

 

2017

 

 

2016

 

 

(Unaudited)

 

 

(In millions)

 

Revenues:

 

 

 

 

 

 

 

Sales of commodities

$

1,858.1

 

 

$

1,171.0

 

Fees from midstream services

 

254.5

 

 

 

271.4

 

Total revenues

 

2,112.6

 

 

 

1,442.4

 

Costs and expenses:

 

 

 

 

 

 

 

Product purchases

 

1,654.2

 

 

 

1,011.0

 

Operating expenses

 

151.9

 

 

 

132.0

 

Depreciation and amortization expense

 

191.1

 

 

 

193.5

 

General and administrative expense

 

45.5

 

 

 

43.4

 

Goodwill impairment

 

 

 

 

24.0

 

Other operating (income) expense

 

16.2

 

 

 

1.0

 

Income from operations

 

53.7

 

 

 

37.5

 

Other income (expense):

 

 

 

 

 

 

 

Interest expense, net

 

(58.6

)

 

 

(46.9

)

Equity earnings (loss)

 

(12.6

)

 

 

(4.8

)

Gain from financing activities

 

 

 

 

24.7

 

Other

 

(8.5

)

 

 

(0.1

)

Income (loss) before income taxes

 

(26.0

)

 

 

10.4

 

Income tax (expense) benefit

 

4.7

 

 

 

0.2

 

Net income (loss)

 

(21.3

)

 

 

10.6

 

Less: Net income attributable to noncontrolling interests

 

6.0

 

 

 

3.0

 

Net income (loss) attributable to Targa Resources Partners LP

$

(27.3

)

 

$

7.6

 

 

 

 

 

 

 

 

 

Net income attributable to preferred limited partners

$

2.8

 

 

$

2.8

 

Net income (loss) attributable to general partner

 

(0.6

)

 

 

14.7

 

Net income (loss) attributable to common limited partners

 

(29.5

)

 

 

(9.9

)

Net income (loss) attributable to Targa Resources Partners LP

$

(27.3

)

 

$

7.6

 

 

See notes to consolidated financial statements.

5


 

TARGA RESOURCE S PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

 

 

 

Three Months Ended March 31,

 

 

 

2017

 

 

2016

 

 

 

 

 

(Unaudited)

 

 

 

(In millions)

 

Net income (loss)

 

$

(21.3

)

 

$

10.6

 

Other comprehensive income (loss):

 

 

 

 

 

 

 

 

Commodity hedging contracts:

 

 

 

 

 

 

 

 

Change in fair value

 

 

66.2

 

 

 

6.7

 

Settlements reclassified to revenues

 

 

6.1

 

 

 

(24.2

)

Other comprehensive income (loss)

 

 

72.3

 

 

 

(17.5

)

Comprehensive income (loss)

 

 

51.0

 

 

 

(6.9

)

Less: Comprehensive income attributable to noncontrolling interests

 

 

6.0

 

 

 

3.0

 

Comprehensive income (loss) attributable to Targa Resources Partners LP

 

$

45.0

 

 

$

(9.9

)

 

See notes to consolidated financial statements.

 

 

 

6


 

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Limited

 

 

Limited

 

 

General

 

 

Other

 

 

Treasury

 

 

Non-

 

 

 

 

 

 

 

Partner

 

 

Partner

 

 

Partner

 

 

Comprehensive

 

 

Units

 

 

controlling

 

 

 

 

 

 

 

Preferred

 

 

Amount

 

 

Common

 

 

Amount

 

 

Units

 

 

Amount

 

 

Income (Loss)

 

 

Units

 

 

Amount

 

 

Interests

 

 

Total

 

 

 

(Unaudited)

 

 

 

(In millions, except units in thousands)

 

Balance December 31, 2016

 

 

5,000

 

 

$

120.6

 

 

 

275,168

 

 

$

5,939.9

 

 

 

5,629

 

 

$

796.7

 

 

$

(61.8

)

 

 

 

 

$

 

 

$

355.2

 

 

$

7,150.6

 

Contributions from Targa

   Resources Corp.

 

 

 

 

 

 

 

 

 

 

 

641.9

 

 

 

 

 

 

13.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

655.0

 

Distributions to noncontrolling

   interests

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(9.7

)

 

 

(9.7

)

Contributions from noncontrolling

   interests

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

8.9

 

 

 

8.9

 

Other comprehensive income

  (loss)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

72.3

 

 

 

 

 

 

 

 

 

 

 

 

72.3

 

Net income (loss)

 

 

 

 

2.8

 

 

 

 

 

 

(29.5

)

 

 

 

 

 

(0.6

)

 

 

 

 

 

 

 

 

 

 

 

6.0

 

 

 

(21.3

)

Distributions

 

 

 

 

 

(2.8

)

 

 

 

 

 

(191.4

)

 

 

 

 

 

(3.9

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(198.1

)

Balance March 31, 2017

 

 

5,000

 

 

$

120.6

 

 

 

275,168

 

 

$

6,360.9

 

 

 

5,629

 

 

$

805.3

 

 

$

10.5

 

 

 

 

 

$

 

 

$

360.4

 

 

$

7,657.7

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Limited

 

 

Limited

 

 

General

 

 

Other

 

Treasury

 

 

Non-

 

 

 

 

 

 

 

Partner

 

 

Partner

 

 

Partner

 

 

Comprehensive

 

 

Units

 

 

controlling

 

 

 

 

 

 

 

Preferred

 

 

Amount

 

 

Common

 

 

Amount

 

 

Units

 

 

Amount

 

 

Income (Loss)

 

 

Units

 

 

Amount

 

 

Interests

 

 

Total

 

 

 

(Unaudited)

 

 

 

(In millions, except units in thousands)

 

Balance December 31, 2015

 

 

5,000

 

 

$

120.6

 

 

 

184,871

 

 

$

4,550.4

 

 

 

3,773

 

 

$

1,735.3

 

 

$

86.8

 

 

 

212

 

 

$

(10.3

)

 

$

420.1

 

 

$

6,902.9

 

Compensation on equity grants

 

 

 

 

 

 

 

 

 

 

 

2.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2.2

 

Distribution equivalent rights

 

 

 

 

 

 

 

 

 

 

 

(0.2

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(0.2

)

Issuance of common units under compensation program

 

 

 

 

 

 

 

 

30

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Units tendered for tax

   withholding obligations

 

 

 

 

 

 

 

 

(1

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1

 

 

 

(0.1

)

 

 

 

 

 

(0.1

)

Cancellation of treasury units

 

 

 

 

 

 

 

 

-

 

 

 

(10.2

)

 

 

 

 

 

(0.2

)

 

 

 

 

 

(213

)

 

 

10.4

 

 

 

 

 

 

 

Contributions from Targa

   Resources Corp.

 

 

 

 

 

 

 

 

45,103

 

 

 

785.0

 

 

 

921

 

 

 

16.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

801.0

 

Distributions to

   noncontrolling interests

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(2.1

)

 

 

(2.1

)

Contributions from noncontrolling interests

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

6.0

 

 

 

6.0

 

Other comprehensive

   income (loss)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(17.5

)

 

 

 

 

 

 

 

 

 

 

 

(17.5

)

Net income

 

 

 

 

 

2.8

 

 

 

 

 

 

(9.9

)

 

 

 

 

 

14.7

 

 

 

 

 

 

 

 

 

 

 

 

3.0

 

 

 

10.6

 

Distributions

 

 

 

 

 

(2.8

)

 

 

 

 

 

(152.5

)

 

 

 

 

 

(47.9

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(203.2

)

Balance March 31, 2016

 

 

5,000

 

 

$

120.6

 

 

 

230,003

 

 

$

5,164.8

 

 

 

4,694

 

 

$

1,717.9

 

 

$

69.3

 

 

 

 

 

$

 

 

$

427.0

 

 

$

7,499.6

 

 

 

See notes to consolidated financial statements.

 

7


 

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

 

Three Months Ended March 31,

 

 

 

2017

 

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Unaudited)

 

 

(In millions)

 

Cash flows from operating activities

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(21.3

)

 

$

10.6

 

Adjustments to reconcile net income (loss) to net cash

   provided by operating activities:

 

 

 

 

 

 

 

 

Amortization in interest expense

 

 

2.4

 

 

 

3.4

 

Compensation on equity grants

 

 

 

 

 

2.2

 

Depreciation and amortization expense

 

 

191.1

 

 

 

193.5

 

Goodwill impairment

 

 

 

 

 

24.0

 

Accretion of asset retirement obligations

 

 

1.3

 

 

 

1.1

 

Increase (decrease) in redemption value of mandatorily redeemable preferred interests

 

 

2.5

 

 

 

(18.5

)

Deferred income tax expense (benefit)

 

 

(0.5

)

 

 

(6.6

)

Equity (earnings) loss of unconsolidated affiliates

 

 

12.6

 

 

 

4.8

 

Distributions of earnings received from unconsolidated affiliates

 

 

2.7

 

 

 

 

Risk management activities

 

 

8.5

 

 

 

4.4

 

(Gain) loss on sale or disposition of assets

 

 

16.1

 

 

 

0.9

 

(Gain) loss from financing activities

 

 

 

 

 

(24.7

)

Change in contingent considerations

 

 

3.3

 

 

 

 

Changes in operating assets and liabilities, net of business acquisitions:

 

 

 

 

 

 

 

 

Receivables and other assets

 

 

140.6

 

 

 

99.3

 

Inventories

 

 

53.7

 

 

 

62.1

 

Accounts payable and other liabilities

 

 

(99.8

)

 

 

(114.5

)

Net cash provided by operating activities

 

 

313.2

 

 

 

242.0

 

Cash flows from investing activities

 

 

 

 

 

 

 

 

Outlays for property, plant and equipment

 

 

(144.2

)

 

 

(190.1

)

Outlays for business acquisition, net of cash acquired

 

 

(480.8

)

 

 

 

Investments in unconsolidated affiliates

 

 

(0.5

)

 

 

 

Return of capital from unconsolidated affiliates

 

 

 

 

 

3.4

 

Other, net

 

 

 

 

 

(1.3

)

Net cash used in investing activities

 

 

(625.5

)

 

 

(188.0

)

Cash flows from financing activities

 

 

 

 

 

 

 

 

Debt obligations:

 

 

 

 

 

 

 

 

     Proceeds from borrowings under credit facility

 

 

480.0

 

 

 

425.0

 

     Repayments of credit facility

 

 

(630.0

)

 

 

(705.0

)

     Proceeds from borrowings under accounts receivable securitization facility

 

 

75.0

 

 

 

5.7

 

     Repayments of accounts receivable securitization facility

 

 

(65.0

)

 

 

(75.0

)

     Redemption of senior notes

 

 

 

 

 

(330.6

)

Costs incurred in connection with financing arrangements

 

 

(0.1

)

 

 

(7.5

)

Repurchase of common units under compensation plans

 

 

 

 

 

(0.1

)

Contributions from general partner

 

 

13.1

 

 

 

16.0

 

Contributions from TRC

 

 

641.9

 

 

 

785.0

 

Contributions from noncontrolling interests

 

 

8.9

 

 

 

6.0

 

Distributions to noncontrolling interests

 

 

(9.7

)

 

 

(2.1

)

Distributions to unitholders

 

 

(198.1

)

 

 

(203.2

)

Payments of distribution equivalent rights

 

 

 

 

 

(0.3

)

Net cash provided by (used in) financing activities

 

 

316.0

 

 

 

(86.1

)

Net change in cash and cash equivalents

 

 

3.7

 

 

 

(32.1

)

Cash and cash equivalents, beginning of period

 

 

68.0

 

 

 

135.4

 

Cash and cash equivalents, end of period

 

$

71.7

 

 

$

103.3

 

 

See notes to consolidated financial statements.

 

8


 

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:

 

gathering, compressing, treating, processing and selling natural gas;

 

storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters;

 

gathering, storing and terminaling crude oil; and

 

storing, terminaling and selling refined petroleum products.

 

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.

 

 

9


 

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.

10


 

In May 2016, the FASB issued ASU 2 016-12, 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, a nd 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

11


 

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 en tities 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 resul ted 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.  

 

 

 

 

 

 

 

12


 

Note 4 – Busin ess 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.

 

 

 

March 31, 2017

 

 

March 31, 2016

 

 

 

Pro Forma

 

 

Pro Forma

 

Revenues

 

$

2,126.7

 

 

$

1,445.0

 

Net income (loss)

 

 

(22.7

)

 

 

(7.5

)

 

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:

 

 

Reflect the amortization expense resulting from the preliminary estimate of the fair value of intangible assets recognized as part of the Permian Acquisition. For the purposes of preparing the pro forma adjustments we have assumed 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.

 

13


 

 

Reflect the change in depreciation expense resulting from the difference between the historical balances of the Permian Acquisition’s property, plant and equipment, net, and the preliminary estimate of the fair value of property, plant and equipment acquired.

 

 

Exclude $5.1 million of acquisition-related costs incurred as of March 31, 2017 from pro forma net income for the three months ended March 31, 2017. Pro forma net income for the three months ended March 31, 2016 was adjusted to include those charges.

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

 

Fair Value of Consideration Transferred:

 

 

 

 

Cash paid, net of cash acquired (1)

 

$

480.8

 

Purchase consideration payable (2)

 

 

90.0

 

Contingent consideration

 

 

461.6

 

Total

 

$

1,032.4

 

 

(1)

Net of cash acquired of $3.3 million.

(2)

The payable will be settled in cash within 90 days from March 1, 2017.

 

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:

 

Fair value determination:

 

March 1, 2017

 

Trade and other current receivables, net

 

$

6.5

 

Other current assets

 

 

0.6

 

Property, plant and equipment

 

 

255.4

 

Intangible assets

 

 

625.6

 

Current liabilities

 

 

(14.3

)

Other long-term liabilities

 

 

(0.4

)

Total identifiable net assets

 

 

873.4

 

Goodwill

 

 

159.0

 

Total fair value of consideration transferred

 

$

1,032.4

 

 

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.

 

 

 

 

 

14


 

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

 

 

 

March 31, 2017

 

 

December 31, 2016

 

Commodities

 

$

65.1

 

 

$

126.9

 

Materials and supplies

 

 

10.4

 

 

 

10.8

 

 

 

$

75.5

 

 

$

137.7

 

 

 

Note 6 — Property, Plant and Equipment and Intangible Assets

 

Property, Plant and Equipment

 

 

 

March 31, 2017

 

 

December 31, 2016

 

 

Estimated Useful Lives (In Years)

Gathering systems

 

$

6,777.7

 

 

$

6,626.9

 

 

5 to 20

Processing and fractionation facilities

 

 

3,500.4

 

 

 

3,383.6

 

 

5 to 25

Terminaling and storage facilities

 

 

1,231.7

 

 

 

1,205.0

 

 

5 to 25

Transportation assets

 

 

427.9

 

 

 

451.4

 

 

10 to 25

Other property, plant and equipment

 

 

280.4

 

 

 

274.0

 

 

3 to 25

Land

 

 

121.5

 

 

 

121.2

 

 

Construction in progress

 

 

610.6

 

 

 

449.8

 

 

Property, plant and equipment

 

 

12,950.2

 

 

 

12,511.9

 

 

 

Accumulated depreciation

 

 

(2,986.8

)

 

 

(2,821.0

)

 

 

Property, plant and equipment, net

 

$

9,963.4

 

 

$

9,690.9

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Intangible assets

 

$

2,662.2

 

 

$

2,036.6

 

 

15 to 20

Accumulated amortization

 

 

(423.4

)

 

 

(382.6

)

 

 

Intangible assets, net

 

$

2,238.8

 

 

$

1,654.0

 

 

 

 

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

15


 

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 ne gotiation, 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:

 

Balance at December 31, 2016

 

$

1,654.0

 

Additions from Permian Acquisition

 

 

625.6

 

Amortization

 

 

(40.8

)

Balance at March 31, 2017

 

$

2,238.8

 

 

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:

 

 

 

WestTX

 

 

SouthTX

 

 

Permian

 

 

Total

 

Balance at December 31, 2016, net

 

$

174.7

 

 

$

35.3

 

 

$

 

 

$

210.0

 

Permian Acquisition, March 1, 2017 (preliminary valuation)

 

 

 

 

 

 

 

 

159.0

 

 

 

159.0

 

Balance at March 31, 2017, net

 

$

174.7

 

 

$

35.3

 

 

$

159.0

 

 

$

369.0

 

 

 

 

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.

16


 

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

 

 

 

GCF

 

 

T2 LaSalle

 

 

T2 Eagle Ford

 

 

T2 EF Cogen

 

 

Total

 

Balance at December 31, 2016

 

$

46.1

 

 

$

58.6

 

 

$

118.6

 

 

$

17.5

 

 

$

240.8

 

Equity earnings (loss)

 

 

3.7

 

 

 

(1.1

)

 

 

(2.7

)

 

 

(12.5

)

 

 

(12.6

)

Cash distributions (1)

 

 

(2.7

)

 

 

 

 

 

 

 

 

 

 

 

(2.7

)

Contributions for expansion projects (2)

 

 

 

 

 

0.3

 

 

 

1.1

 

 

 

0.1

 

 

 

1.5

 

Balance at March 31, 2017

 

$

47.1

 

 

$

57.8

 

 

$

117.0

 

 

$

5.1

 

 

$

227.0

 

 

(1)

During the three months ended March 31, 2017, there were no distributions received in excess of our share of cumulative earnings. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows in the period in which they occur.

(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

 

 

 

March 31, 2017

 

 

December 31, 2016

 

Commodities

 

$

511.9

 

 

$

574.5

 

Other goods and services

 

 

120.7

 

 

 

113.4

 

Purchase consideration payable

 

 

90.0

 

 

 

-

 

Interest

 

 

51.5

 

 

 

52.2

 

Income and other taxes

 

 

22.5

 

 

 

19.1

 

Other

 

 

22.9

 

 

 

14.7

 

 

 

$

819.5

 

 

$

773.9

 

 

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.

 

 

17


 

Note 10 — De bt Obligations

 

 

 

March 31, 2017

 

 

December 31, 2016

 

 

 

 

 

 

 

 

 

 

Current:

 

 

 

 

 

 

 

 

Accounts receivable securitization facility, due December 2017

 

$

285.0

 

 

$

275.0

 

Senior unsecured notes, 5% fixed rate, due January 2018

 

 

250.5

 

 

 

 

 

 

 

535.5

 

 

 

275.0

 

Debt issuance costs, net of amortization

 

 

(0.6

)

 

 

 

Current maturities of debt

 

 

534.9

 

 

 

275.0

 

Long-term:

 

 

 

 

 

 

 

 

Senior secured revolving credit facility, variable rate, due October 2020 (1)

 

 

 

 

 

150.0

 

Senior unsecured notes:

 

 

 

 

 

 

 

 

5% fixed rate, due January 2018

 

 

 

 

 

250.5

 

4 % fixed rate, due November 2019

 

 

749.4

 

 

 

749.4

 

6 % fixed rate, due August 2022

 

 

278.7

 

 

 

278.7

 

5 ¼ % fixed rate, due May 2023

 

 

559.6

 

 

 

559.6

 

4¼% fixed rate, due November 2023

 

 

583.9

 

 

 

583.9

 

6¾% fixed rate, due March 2024

 

 

580.1

 

 

 

580.1

 

5⅛ % fixed rate, due February 2025

 

 

500.0

 

 

 

500.0

 

5⅜ % fixed rate, due February 2027

 

 

500.0

 

 

 

500.0

 

TPL notes, 4¾% fixed rate, due November 2021 (2)

 

 

6.5

 

 

 

6.5

 

TPL notes, 5⅞% fixed rate, due August 2023 (2)

 

 

48.1

 

 

 

48.1

 

Unamortized premium

 

 

0.5

 

 

 

0.5

 

 

 

 

3,806.8

 

 

 

4,207.3

 

Debt issuance costs, net of amortization

 

 

(28.5

)

 

 

(30.3

)

Long-term debt

 

 

3,778.3

 

 

 

4,177.0

 

Total debt obligations

 

$

4,313.2

 

 

$

4,452.0

 

Irrevocable standby letters of credit outstanding

 

$

15.8

 

 

$

13.2

 

 

(1)

As of March 31, 2017, availability under our $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,584.2 million.

(2)

Targa Pipeline Partners, L.P. (“TPL”) notes are not guaranteed by us.

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:

 

 

 

Range of Interest

Rates Incurred

 

 

Weighted Average

Interest Rate

Incurred

 

TRP Revolver

 

3.0% - 5.3%

 

 

 

3.2%

 

Accounts receivable securitization facility

 

 

1.8%

 

 

 

1.8%

 

 

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.

 

 

 

18


 

Note 11 — Other Long-term Liabilities

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

 

 

 

March 31, 2017

 

 

December 31, 2016

 

Asset retirement obligations

 

$

67.5

 

 

$

64.1

 

Mandatorily redeemable preferred interests

 

 

71.9

 

 

 

68.5

 

Deferred revenue

 

 

69.0

 

 

 

69.8

 

Permian Acquisition contingent consideration

 

 

464.8

 

 

 

-

 

Other liabilities

 

 

3.2

 

 

 

2.9

 

Total long-term liabilities

 

$

676.4

 

 

$

205.3

 

 

Asset Retirement Obligations

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

 

Balance at December 31, 2016

 

$

64.1

 

Additions (1)

 

 

0.4

 

Change in cash flow estimate

 

 

1.7

 

Accretion expense

 

 

1.3

 

Balance at March 31, 2017

 

$

67.5

 

_____________________________________________________________________________________________________________________________________________________________

 

(1)

Amount reflects AROs assumed from the Permian Acquisition

 

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:

 

Balance at December 31, 2016

 

$

68.5

 

Income attributable to mandatorily redeemable preferred interests

 

 

0.9

 

Change in estimated redemption value included in interest expense

 

 

2.5

 

Balance at March 31, 2017

 

$

71.9

 

 

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

19


 

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 throug h 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:

 

 

 

March 31, 2017

 

 

December 31, 2016

 

Splitter agreement

 

$

43.0

 

 

$

43.0

 

Gas contract amendment

 

 

19.3

 

 

 

19.7

 

Other deferred revenue

 

 

6.7

 

 

 

7.1

 

Total deferred revenue

 

$

69.0

 

 

$

69.8

 

 

The following table shows the changes in deferred revenue:

 

Balance at December 31, 2016

 

$

69.8

 

Additions

 

 

-

 

Revenue recognized

 

 

(0.8

)

Balance at March 31, 2017

 

$

69.0

 

 

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. S ee Note 1 – Organization and Operations.

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

 

 

 

 

 

 

 

 

 

 

 

Three Months

 

Date Paid

 

Total

 

 

Distributions   to

Targa   Resources

 

Ended

 

Or to Be Paid

 

Distributions

 

 

Corp.

 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2017

 

May 11, 2017

$

 

209.6

 

$

 

206.8

 

December 31, 2016

 

February 10, 2017

 

 

198.1

 

 

 

195.3

 

 

20


 

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. 

21


 

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

 

Commodity

Instrument

Unit

2017

 

2018

 

2019

 

Natural Gas

Swaps

MMBtu/d

 

141,960

 

 

100,500

 

 

61,383

 

Natural Gas

Basis Swaps

MMBtu/d

 

95,963

 

 

1,103

 

 

-

 

Natural Gas

Futures

MMBtu/d

 

-

 

 

1,103

 

 

-

 

Natural Gas

Options

MMBtu/d

 

22,900

 

 

9,486

 

 

-

 

NGL

Swaps

Bbl/d

 

14,143

 

 

6,658

 

 

5,339

 

NGL

Futures

Bbl/d

 

5,702

 

 

1,288

 

 

-

 

NGL

Options

Bbl/d

 

1,647

 

 

1,676

 

 

-

 

Condensate

Swaps

Bbl/d

 

2,690

 

 

2,190

 

 

1,063

 

Condensate

Options

Bbl/d

 

1,380

 

 

691

 

 

590

 

 

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:

 

 

 

 

 

Fair Value as of March 31, 2017

 

 

Fair Value as of December 31, 2016

 

 

 

Balance Sheet

 

Derivative

 

 

Derivative

 

 

Derivative

 

 

Derivative

 

 

 

Location

 

Assets

 

 

Liabilities

 

 

Assets

 

 

Liabilities

 

Derivatives designated as hedging instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Current

 

$

23.6

 

 

$

20.8

 

 

$

16.7

 

 

$

48.6

 

 

 

Long-term

 

 

21.6

 

 

 

7.9

 

 

 

5.1

 

 

 

26.1

 

Total derivatives designated as hedging instruments

 

 

 

$

45.2

 

 

$

28.7

 

 

$

21.8

 

 

$

74.7

 

Derivatives not designated as hedging instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Current

 

$

0.3

 

 

$

1.4

 

 

$

0.1

 

 

$

0.5

 

Total derivatives not designated as hedging instruments

 

 

 

$

0.3

 

 

$

1.4

 

 

$

0.1

 

 

$

0.5

 

Total current position

 

 

 

$

23.9

 

 

$

22.2

 

 

$

16.8

 

 

$

49.1

 

Total long-term position

 

 

 

 

21.6

 

 

 

7.9

 

 

 

5.1

 

 

 

26.1

 

Total derivatives

 

 

 

$

45.5

 

 

$

30.1

 

 

$

21.9

 

 

$

75.2

 

 

22


 

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

 

 

 

Gross Presentation

 

 

Pro forma net presentation

 

March 31, 2017

Asset

 

 

Liability

 

 

Collateral

 

 

Asset

 

 

Liability

 

Current Position

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Counterparties with offsetting positions or collateral

$

23.8

 

 

$

(20.8

)

 

$

0.1

 

 

$

10.8

 

 

$

(7.7

)

 

Counterparties without offsetting positions - assets

 

0.1

 

 

 

-

 

 

 

-

 

 

 

0.1

 

 

 

-

 

 

Counterparties without offsetting positions - liabilities

 

-

 

 

 

(1.4

)

 

 

-

 

 

 

-

 

 

 

(1.4

)

 

 

 

23.9

 

 

 

(22.2

)

 

 

0.1

 

 

 

10.9

 

 

 

(9.1

)

Long Term Position

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Counterparties with offsetting positions or collateral

 

21.3

 

 

 

(6.6

)

 

 

-

 

 

 

16.7

 

 

 

(2.0

)

 

Counterparties without offsetting positions - assets

 

0.3

 

 

 

-

 

 

 

-

 

 

 

0.3

 

 

 

-

 

 

Counterparties without offsetting positions - liabilities

 

-

 

 

 

(1.3

)

 

 

-

 

 

 

-

 

 

 

(1.3

)

 

 

 

21.6

 

 

 

(7.9

)

 

 

-

 

 

 

17.0

 

 

 

(3.3

)

Total Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Counterparties with offsetting positions or collateral

 

45.1

 

 

 

(27.4

)

 

 

0.1

 

 

 

27.5

 

 

 

(9.7

)

 

Counterparties without offsetting positions - assets

 

0.4

 

 

 

-

 

 

 

-

 

 

 

0.4

 

 

 

-

 

 

Counterparties without offsetting positions - liabilities

 

-

 

 

 

(2.7

)

 

 

-

 

 

 

-

 

 

 

(2.7

)

 

 

$

45.5

 

 

$

(30.1

)

 

$

0.1

 

 

$

27.9

 

 

$

(12.4

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross Presentation

 

 

Pro forma net presentation

 

December 31, 2016

Asset

 

 

Liability

 

 

Collateral

 

 

Asset

 

 

Liability

 

Current Position

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Counterparties with offsetting positions or collateral

$

16.8

 

 

$

(46.1

)

 

$

7.0

 

 

$

5.7

 

 

$

(28.0

)

 

Counterparties without offsetting positions - assets

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

Counterparties without offsetting positions - liabilities

 

-

 

 

 

(3.0

)

 

 

-

 

 

 

-

 

 

 

(3.0

)

 

 

 

16.8

 

 

 

(49.1

)

 

 

7.0

 

 

 

5.7

 

 

 

(31.0

)

Long Term Position

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Counterparties with offsetting positions or collateral

 

5.1

 

 

 

(18.7

)

 

 

-

 

 

 

-

 

 

 

(13.6

)

 

Counterparties without offsetting positions - assets

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

Counterparties without offsetting positions - liabilities

 

-

 

 

 

(7.4

)

 

 

-

 

 

 

-

 

 

 

(7.4

)

 

 

 

5.1

 

 

 

(26.1

)

 

 

-

 

 

 

-

 

 

 

(21.0

)

Total Derivatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Counterparties with offsetting positions or collateral

 

21.9

 

 

 

(64.8

)

 

 

7.0

 

 

 

5.7

 

 

 

(41.6

)

 

Counterparties without offsetting positions - assets

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

Counterparties without offsetting positions - liabilities

 

-

 

 

 

(10.4

)

 

 

-

 

 

 

-

 

 

 

(10.4

)

 

 

$

21.9

 

 

$

(75.2

)

 

$

7.0

 

 

$

5.7

 

 

$

(52.0

)

 

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:

 

 

 

Gain (Loss) Recognized in OCI on

Derivatives (Effective Portion)

 

Derivatives in Cash Flow

 

Three Months Ended March 31,

 

Hedging Relationships

 

2017

 

 

2016

 

Commodity contracts

 

$

66.2

 

 

$

6.7

 

23


 

 

 

 

Gain (Loss) Reclassified from OCI into

Income (Effective Portion)

 

 

 

Three Months Ended March 31,

 

Location of Gain (Loss)

 

2017

 

 

2016

 

Revenues

 

$

(6.1

)

 

$

24.2

 

 

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.

 

 

 

Location of Gain

 

Gain (Loss) Recognized in Income on Derivatives

 

Derivatives Not Designated

 

Recognized in Income on

 

Three Months Ended March 31,

 

as Hedging Instruments

 

Derivatives

 

2017

 

 

2016

 

Commodity contracts

 

Revenue

 

$

(0.8

)

 

$

1.8

 

 

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:

 

The TRP Revolver and the accounts receivable securitization facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and

 

Senior unsecured notes are based on quoted market prices derived from trades of the debt.

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

24


 

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:

 

Level 1 – observable inputs such as quoted prices in active markets;

 

Level 2 – inputs other than quoted prices in active markets that we can directly or indirectly observe to the extent that the markets are liquid for the relevant settlement periods; and

 

Level 3 – unobservable inputs in which little or no market data exists, therefore we must develop our own assumptions.

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:

 

 

 

March 31, 2017

 

 

 

 

 

 

 

Fair Value

 

 

 

Carrying Value

 

 

Total

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

Financial Instruments Recorded on Our

   Consolidated Balance Sheets at Fair Value:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets from commodity derivative contracts (1)

 

$

37.7

 

 

$

37.7

 

 

$

 

 

$

35.7

 

 

$

2.0

 

Liabilities from commodity derivative contracts (1)

 

 

22.1

 

 

 

22.1

 

 

 

 

 

 

20.8

 

 

 

1.3

 

Permian Acquisition contingent consideration (2)

 

 

 

464.8

 

 

 

464.8

 

 

 

 

 

 

 

 

 

464.8

 

TPL contingent consideration (3)

 

 

2.7

 

 

 

2.7

 

 

 

 

 

 

 

 

 

2.7

 

Financial Instruments Recorded on Our

   Consolidated Balance Sheets at Carrying Value:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

71.7

 

 

 

71.7

 

 

 

 

 

 

 

 

 

 

TRP Revolver

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Senior unsecured notes

 

 

4,057.3

 

 

 

4,169.1

 

 

 

 

 

 

4,169.1

 

 

 

 

Accounts receivable securitization facility

 

 

285.0

 

 

 

285.0

 

 

 

 

 

 

285.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2016

 

 

 

 

 

 

Fair Value

 

 

 

Carrying Value

 

Total

 

Level 1

 

Level 2

 

Level 3

 

Financial Instruments Recorded on Our

   Consolidated Balance Sheets at Fair Value:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets from commodity derivative contracts (1)

 

$

21.0

 

 

$

21.0

 

 

$

 

 

$

19.6

 

 

$

1.4

 

Liabilities from commodity derivative contracts (1)

 

 

74.2

 

 

 

74.2

 

 

 

 

 

 

69.3

 

 

 

4.9

 

TPL contingent consideration (3)

 

 

2.6

 

 

 

2.6

 

 

 

 

 

 

 

 

 

2.6

 

Financial Instruments Recorded on Our

   Consolidated Balance Sheets at Carrying Value:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

68.0

 

 

 

68.0

 

 

 

 

 

 

 

 

 

 

TRP Revolver

 

 

150.0

 

 

 

150.0

 

 

 

 

 

 

150.0

 

 

 

 

Senior unsecured notes

 

 

4,057.3

 

 

 

4,101.6

 

 

 

 

 

 

4,101.6

 

 

 

 

Accounts receivable securitization facility

 

 

275.0

 

 

 

275.0

 

 

 

 

 

 

275.0

 

 

 

 

 

(1)

The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 13 – Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes.

(2)

We have a contingent consideration liability related to the Permian Acquisition. See Note 4 – Business Acquisitions and Divestitures.

(3)

We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which are carried at fair value.

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.

25


 

The fair value of these swaps is determined using a discounted cash flow valuation technique based on a forward c ommodity 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:

 

 

 

 

Commodity

 

 

 

 

 

 

 

 

Derivative Contracts

 

 

Contingent

 

 

 

 

Asset/(Liability)

 

 

Liability

 

 

 

 

 

 

 

 

 

 

 

Balance, December 31, 2016

 

$

(3.6

)

 

$

(2.6

)

 

Change in fair value of TPL contingent consideration

 

 

-

 

 

 

(0.1

)

 

Fair value of Permian Acquisition contingent consideration (1)

 

 

-

 

 

 

(464.8

)

 

New Level 3 derivative instruments

 

 

(0.1

)

 

 

-

 

 

Transfers out of Level 3 (2)

 

 

1.6

 

 

 

-

 

 

Settlements included in Revenue

 

 

0.2

 

 

 

-

 

 

Unrealized gain/(loss) included in OCI

 

 

2.6

 

 

 

-

 

Balance, March 31, 2017

 

$

0.7

 

 

$

(467.5

)

 

(1)

Represents the March 31, 2017 balance of the contingent consideration that arose as part of the Permian Acquisition in Q1 2017. See Note 4 – Business Acquisitions and Divestitures for discussion of the initial fair value.

(2)

Transfers relate to long-term over-the-counter swaps for NGL products for which observable market prices became available for substantially their full term.

 

 

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.

26


 

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

 

 

Three Months Ended March 31,

 

 

 

2017

 

 

2016

 

Targa billings of payroll and related costs included in operating expense

 

$

47.0

 

 

$

40.2

 

Targa allocation of general and administrative expense

 

 

42.0

 

 

 

39.9

 

Cash distributions to Targa based on IDR, GP and common unit ownership (1)

 

 

195.3

 

 

 

61.4

 

Cash contributions from Targa related to limited partner ownership (2)

 

 

641.9

 

 

 

785.0

 

Cash contributions from Targa to maintain its 2% general partner ownership

 

 

13.1

 

 

 

16.0

 

_______________________

(1)

As a result of the Third A&R Partnership Agreement, 2017 cash distributions to Targa are only based on GP and common unit ownership.

(2)

The 2016 cash contributions from Targa related to limited partner ownership were contributed for the issuance of common units. The 2017 cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partnership and 2% to GP. See Note 12 – Partnership Units and Related Matters.

 

 

27


 

 

 

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:

 

 

Three Months Ended March 31,

 

 

2017

 

 

2016

 

(Gain) loss on sale or disposal of assets (1)

$

16.1

 

 

$

0.9

 

Miscellaneous business tax

 

0.1

 

 

 

0.1

 

 

$

16.2

 

 

$

1.0

 

 

(1)

Comprised primarily of a $16.1 million loss in 2017 due to the reduction in the carrying value of our ownership interest in VGS in connection with the April 4, 2017 sale.

 

28


 

 

Note 18 — Supplemental Cash Flow Information

 

 

 

Three Months Ended March 31,

 

 

 

2017

 

 

 

2016

 

Cash:

 

 

 

 

 

 

 

 

 

Interest paid, net of capitalized interest (1)

$

 

53.5

 

 

$

 

77.3

 

Income taxes paid, net of refunds

 

 

(0.1

)

 

 

 

1.1

 

Non-cash investing activities:

 

 

 

 

 

 

 

 

 

Deadstock commodity inventory transferred to property, plant and equipment

$

 

8.3

 

 

$

 

16.9

 

Impact of capital expenditure accruals on property, plant and equipment

 

 

30.0

 

 

 

 

13.7

 

Transfers from materials and supplies inventory to property, plant and equipment

 

 

0.4

 

 

 

 

0.5

 

Contribution of property, plant and equipment to investment in unconsolidated affiliates.

 

 

1.0

 

 

 

 

 

Change in ARO liability and property, plant and equipment due to revised cash flow estimate

 

 

1.7

 

 

 

 

(9.1

)

Non-cash balance sheet movements related to the Permian Acquisition:

 

 

 

 

 

 

 

 

 

Contingent consideration recorded at the acquisition date

$

 

461.6

 

 

$

 

 

Purchase consideration payable recorded for the Permian Acquisition

 

 

90.0

 

 

 

 

 

Non-cash financing activities:

 

 

 

 

 

 

 

 

 

Cancellation of treasury units

$

 

 

 

$

 

(10.2

)

Accrued distributions on unvested equity awards under share

   compensation arrangements

 

 

 

 

 

 

0.2

 

_____________

 

(1)

Interest capitalized on major projects was $1.7 million and $4.8 million for the three months ended March 31, 2017 and 2016.

 

 

 

29


 

Note 19 — Segm ent 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:

 

 

 

Three Months Ended March 31, 2017

 

 

 

Gathering and Processing

 

 

Logistics and Marketing

 

 

Other

 

 

Corporate

and

Eliminations

 

 

Total

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales of commodities

 

$

166.7

 

 

$

1,692.4

 

 

$

(1.0

)

 

$

 

 

$

1,858.1

 

Fees from midstream

   services

 

 

118.2

 

 

 

136.3

 

 

 

 

 

 

 

 

 

254.5

 

 

 

 

284.9

 

 

 

1,828.7

 

 

 

(1.0

)

 

 

 

 

 

2,112.6

 

Intersegment revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales of commodities

 

 

713.0

 

 

 

75.4

 

 

 

 

 

 

(788.4

)

 

 

 

Fees from midstream

   services

 

 

1.9

 

 

 

7.0

 

 

 

 

 

 

(8.9

)

 

 

 

 

 

 

714.9

 

 

 

82.4

 

 

 

 

 

 

(797.3

)

 

 

 

Revenues

 

$

999.8

 

 

$

1,911.1

 

 

$

(1.0

)

 

$

(797.3

)

 

$

2,112.6

 

Operating margin

 

$

177.4

 

 

$

130.1

 

 

$

(1.0

)

 

$

 

 

$

306.5

 

Other financial information:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets (1)

 

$

10,780.4

 

 

$

2,687.2

 

 

$

44.8

 

 

$

57.4

 

 

$

13,569.8

 

Goodwill

 

$

369.0

 

 

$

 

 

$

 

 

$

 

 

$

369.0

 

Capital expenditures

 

$

139.2

 

 

$

34.6

 

 

$

 

 

$

0.8

 

 

$

174.6

 

 

(1)

Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver.

 

30


 

 

 

Three Months Ended March 31, 2016

 

 

 

Gathering and Processing

 

 

Logistics and Marketing

 

 

Other

 

 

Corporate

and

Eliminations

 

 

Total

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales of commodities

 

$

110.3

 

 

$

1,033.9

 

 

$

26.8

 

 

$

 

 

$

1,171.0

 

Fees from midstream

   services

 

 

115.8

 

 

 

155.6

 

 

 

 

 

 

 

 

 

271.4

 

 

 

 

226.1

 

 

 

1,189.5

 

 

 

26.8

 

 

 

 

 

 

1,442.4

 

Intersegment revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales of commodities

 

 

412.6

 

 

 

47.3

 

 

 

 

 

 

(459.9

)

 

 

 

Fees from midstream

   services

 

 

2.1

 

 

 

4.1

 

 

 

 

 

 

(6.2

)

 

 

 

 

 

 

414.7

 

 

 

51.4

 

 

 

 

 

 

(466.1

)

 

 

 

Revenues

 

$

640.8

 

 

$

1,240.9

 

 

$

26.8

 

 

$

(466.1

)

 

$

1,442.4

 

Operating margin

 

$

115.6

 

 

$

157.0

 

 

$

26.8

 

 

$

 

 

$

299.4

 

Other financial information:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets (1)

 

$

10,219.0

 

 

$

2,501.0

 

 

$

105.7

 

 

$

42.9

 

 

$

12,868.6

 

Goodwill

 

$

393.0

 

 

$

 

 

$

 

 

$

 

 

$

393.0

 

Capital expenditures

 

$

103.0

 

 

$

73.1

 

 

$

 

 

$

0.8

 

 

$

176.9

 

 

(1)

Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver.

 

 

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

 

 

Three Months Ended March 31,

 

 

2017

 

 

2016

 

Sales of commodities:

 

 

 

 

 

 

 

Natural gas

$

480.9

 

 

$

326.9

 

NGL

 

1,314.9

 

 

 

785.8

 

Condensate

 

43.6

 

 

 

22.2

 

Petroleum products

 

19.8

 

 

 

9.6

 

Derivative activities

 

(1.1

)

 

 

26.5

 

 

 

1,858.1

 

 

 

1,171.0

 

Fees from midstream services:

 

 

 

 

 

 

 

Fractionating and treating

 

31.0

 

 

 

30.2

 

Storage, terminaling, transportation and export

 

99.7

 

 

 

118.4

 

Gathering and processing

 

107.7

 

 

 

105.0

 

Other

 

16.1

 

 

 

17.8

 

 

 

254.5

 

 

 

271.4

 

Total revenues

$

2,112.6

 

 

$

1,442.4

 

 

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

 

 

 

Three Months Ended March 31,

 

 

 

2017

 

 

 

2016

 

Reconciliation of operating margin to net income (loss):

 

 

 

 

 

 

 

 

 

Operating margin

 

$

306.5

 

 

 

$

299.4

 

Depreciation and amortization expenses

 

 

(191.1

)

 

 

 

(193.5

)

General and administrative expenses

 

 

(45.5

)

 

 

 

(43.4

)

Goodwill impairment

 

 

-

 

 

 

 

(24.0

)

Interest expense, net

 

 

(58.6

)

 

 

 

(46.9

)

Other, net

 

 

(37.3

)

 

 

 

18.8

 

Income tax (expense) benefit

 

 

4.7

 

 

 

 

0.2

 

Net income (loss)

 

$

(21.3

)

 

 

$

10.6

 

 

 

 

31


 

Item 2. Management’s Discussion and Analysis o f 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:

 

gathering, compressing, treating, processing and selling natural gas;

 

storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters;

 

gathering, storing and terminaling crude oil; and

 

storing, terminaling and selling refined petroleum products.

 

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.

 

 

 

 

32


 

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,

33


 

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 jo int 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 o n 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.

34


 

Our profitability is also impacted by fee-based revenues. Our growth strategy, based on expansion of existing facilities as well as third-party acqu isitions 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 commoditie s.

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.

35


 

Logistics and Marketing segment gross margin consists primarily of

 

service fee revenues (including the pass-through of energy costs included in fee rates),  

 

system product gains and losses, and  

 

NGL and natural gas sales, less NGL and natural gas purchases, transportation costs and the net inventory change.

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:

 

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

 

our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

 

the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

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.

 

36


 

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.

 

Three Months Ended March 31,

 

 

2017

 

 

2016

 

 

(In millions)

 

Reconciliation of Net Income (loss) to TRP Operating Margin and Gross Margin:

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(21.3

)

 

$

10.6

 

Depreciation and amortization expense

 

 

191.1

 

 

 

193.5

 

General and administrative expense

 

 

45.5

 

 

 

43.4

 

Goodwill impairment

 

 

 

 

 

24.0

 

Interest expense, net

 

 

58.6

 

 

 

46.9

 

Income tax expense (benefit)

 

 

(4.7

)

 

 

(0.2

)

(Gain) loss on sale or disposition of assets

 

 

16.1

 

 

 

0.9

 

(Gain) loss from financing activities

 

 

 

 

 

(24.7

)

Other, net

 

 

21.2

 

 

 

5.0

 

Operating margin

 

 

306.5

 

 

 

299.4

 

Operating expenses

 

 

151.9

 

 

 

132.0

 

Gross margin

 

$

458.4

 

 

$

431.4

 

 

 

Three Months Ended March 31,

 

 

2017

 

 

2016

 

 

(In millions)

 

Reconciliation of Net Income (Loss) attributable to TRP to Adjusted EBITDA

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to TRP

$

 

(27.3

)

 

$

 

7.6

 

Interest expense, net

 

 

58.6

 

 

 

 

46.9

 

Income tax expense (benefit)

 

 

(4.7

)

 

 

 

(0.2

)

Depreciation and amortization expense

 

 

191.1

 

 

 

 

193.5

 

Goodwill impairment

 

 

 

 

 

 

24.0

 

(Gain) loss on sale or disposition of assets

 

 

16.1

 

 

 

 

0.9

 

(Gain) loss from financing activities

 

 

 

 

 

 

(24.7

)

(Earnings) loss from unconsolidated affiliates

 

 

12.6

 

 

 

 

4.8

 

Distributions from unconsolidated affiliates and preferred partner interests, net

 

 

4.2

 

 

 

 

5.8

 

Change in contingent consideration

 

 

3.3

 

 

 

 

 

Compensation on TRP equity grants

 

 

 

 

 

 

2.2

 

Transaction costs related to business acquisitions

 

 

5.1

 

 

 

 

 

Splitter Agreement (1)

 

 

10.8

 

 

 

 

 

Risk management activities

 

 

3.6

 

 

 

 

5.9

 

Noncontrolling interests adjustments (2)

 

 

(4.3

)

 

 

 

(5.8

)

TRP Adjusted EBITDA

$

 

269.1

 

 

$

 

260.9

 

 

(1)

The Splitter Agreement adjustment represents the recognition of the annual cash payment received under the condensate splitter agreement recognized over the four quarters following receipt.

(2)

Noncontrolling interest portion of depreciation and amortization expense.

37


 

Consolidated Results of Operations

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

 

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

2017

 

 

 

2016

 

 

 

2017 vs. 2016

 

 

(In millions, except operating statistics and price amounts)

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales of commodities

 

 

$

1,858.1

 

 

 

$

1,171.0

 

 

 

$

687.1

 

 

 

59

%

Fees from midstream services

 

 

 

254.5

 

 

 

 

271.4

 

 

 

 

(16.9

)

 

 

(6

%)

Total revenues

 

 

 

2,112.6

 

 

 

 

1,442.4

 

 

 

 

670.2

 

 

 

46

%

Product purchases

 

 

 

1,654.2

 

 

 

 

1,011.0

 

 

 

 

643.2

 

 

 

64

%

Gross margin (1)

 

 

 

458.4

 

 

 

 

431.4

 

 

 

 

27.0

 

 

 

6

%

Operating expenses

 

 

 

151.9

 

 

 

 

132.0

 

 

 

 

19.9

 

 

 

15

%

Operating margin (1)

 

 

 

306.5

 

 

 

 

299.4

 

 

 

 

7.1

 

 

 

2

%

Depreciation and amortization expense

 

 

 

191.1

 

 

 

 

193.5

 

 

 

 

(2.4

)

 

 

(1

%)

General and administrative expense

 

 

 

45.5

 

 

 

 

43.4

 

 

 

 

2.1

 

 

 

5

%

Goodwill impairment

 

 

 

 

 

 

 

24.0

 

 

 

 

(24.0

)

 

 

(100

%)

Other operating (income) expense

 

 

 

16.2

 

 

 

 

1.0

 

 

 

 

15.2

 

 

NM

 

Income from operations

 

 

 

53.7

 

 

 

 

37.5

 

 

 

 

16.2

 

 

 

43

%

Interest expense, net

 

 

 

(58.6

)

 

 

 

(46.9

)

 

 

 

(11.7

)

 

 

25

%

Equity earnings (loss)

 

 

 

(12.6

)

 

 

 

(4.8

)

 

 

 

(7.8

)

 

 

163

%

Gain from financing activities

 

 

 

 

 

 

 

24.7

 

 

 

 

(24.7

)

 

 

(100

%)

Other income (expense)

 

 

 

(8.5

)

 

 

 

(0.1

)

 

 

 

(8.4

)

 

NM

 

Income tax (expense) benefit

 

 

 

4.7

 

 

 

 

0.2

 

 

 

 

4.5

 

 

NM

 

Net income (loss)

 

 

 

(21.3

)

 

 

 

10.6

 

 

 

 

(31.9

)

 

NM

 

Less: Net income attributable to noncontrolling interests

 

 

 

6.0

 

 

 

 

3.0

 

 

 

 

3.0

 

 

 

100

%

Net income (loss) attributable to Targa Resources Partners LP

 

 

$

(27.3

)

 

 

$

7.6

 

 

 

$

(34.9

)

 

NM

 

Financial and operating data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Financial data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Adjusted EBITDA (1)

 

 

$

269.1

 

 

 

$

260.9

 

 

 

$

8.2

 

 

 

3

%

Capital expenditures

 

 

 

174.6

 

 

 

 

176.9

 

 

 

 

(2.3

)

 

 

(1

%)

Business acquisition (2)

 

 

 

1,032.4

 

 

 

 

 

 

 

 

1,032.4

 

 

 

 

Operating statistics: (3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil gathered, Badlands, MBbl/d

 

 

 

113.5

 

 

 

 

108.1

 

 

 

 

5.4

 

 

 

5

%

Crude oil gathered, Permian, MBbl/d (4)

 

 

 

9.2

 

 

 

 

 

 

 

 

9.2

 

 

 

 

Plant natural gas inlet, MMcf/d (5)(6)

 

 

 

3,242.1

 

 

 

 

3,406.0

 

 

 

 

(163.9

)

 

 

(5

%)

Gross NGL production, MBbl/d

 

 

 

291.8

 

 

 

 

284.7

 

 

 

 

7.1

 

 

 

2

%

Export volumes, MBbl/d (7)

 

 

 

217.5

 

 

 

 

181.0

 

 

 

 

36.5

 

 

 

20

%

Natural gas sales, BBtu/d (6)(8)

 

 

 

1,870.2

 

 

 

 

1,974.6

 

 

 

 

(104.4

)

 

 

(5

%)

NGL sales, MBbl/d (8)

 

 

 

533.6

 

 

 

 

547.8

 

 

 

 

(14.2

)

 

 

(3

%)

Condensate sales, MBbl/d

 

 

 

10.7

 

 

 

 

9.5

 

 

 

 

1.2

 

 

 

13

%

 

(1)

Gross margin, operating margin, and adjusted EBITDA are non-GAAP financial measures and are discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations.”

(2)

Includes the $90.0 million payable which will be settled within 90 days from March 1, 2017, and the preliminary acquisition date fair value of the potential earn-out payments of $461.6 million due in 2018 and 2019.

(3)

These volume statistics are presented with the numerator as the total volume sold during the quarter and the denominator as the number of calendar days during the quarter.

(4)

Includes operations from the Permian Acquisition for the period effective March 1, 2017. For the volume statistics presented, the numerator is the total volume sold during the period of our ownership while the denominator is the number of calendar days during the quarter.

(5)

Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant, other than in Badlands, where it represents total wellhead gathered volume.

(6)

Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.

(7)

Export volumes represent the quantity of NGL products delivered to third party customers at our Galena Park Marine Terminal that are destined for international markets.

(8)

Includes the impact of intersegment eliminations.

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

38


 

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 cha nges 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:

 

 

 

Gathering and

Processing

 

 

Logistics and Marketing

 

 

Other

 

 

Total

 

 

(In millions)

 

Three Months Ended:

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2017

 

$

177.4

 

 

$

130.1

 

 

$

(1.0

)

 

$

306.5

 

March 31, 2016

 

 

115.6

 

 

 

157.0

 

 

 

26.8

 

 

 

299.4

 

39


 

Gathering and Processing Segment

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

 

2017

 

 

2016

 

 

2017 vs. 2016

 

Gross margin

$

 

263.0

 

 

$

 

194.1

 

 

$

 

68.9

 

 

 

35

%

Operating expenses

 

 

85.6

 

 

 

 

78.5

 

 

 

 

7.1

 

 

 

9

%

Operating margin

$

 

177.4

 

 

$

 

115.6

 

 

$

 

61.8

 

 

 

53

%

Operating statistics (1):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Plant natural gas inlet, MMcf/d (2),(3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SAOU (4)

 

 

275.6

 

 

 

 

243.5

 

 

 

 

32.1

 

 

 

13

%

WestTX

 

 

536.5

 

 

 

 

461.0

 

 

 

 

75.5

 

 

 

16

%

Total Permian Midland

 

 

812.1

 

 

 

 

704.5

 

 

 

 

107.6

 

 

 

 

 

Sand Hills (4)

 

 

139.5

 

 

 

 

151.1

 

 

 

 

(11.6

)

 

 

(8

%)

Versado

 

 

198.5

 

 

 

 

180.0

 

 

 

 

18.5

 

 

 

10

%

Total Permian Delaware

 

 

338.0

 

 

 

 

331.1

 

 

 

 

6.9

 

 

 

 

 

Total Permian

 

 

1,150.1

 

 

 

 

1,035.6

 

 

 

 

114.5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SouthTX

 

 

171.8

 

 

 

 

175.7

 

 

 

 

(3.9

)

 

 

(2

%)

North Texas

 

 

282.5

 

 

 

 

327.5

 

 

 

 

(45.0

)

 

 

(14

%)

SouthOK

 

 

440.4

 

 

 

 

457.9

 

 

 

 

(17.5

)

 

 

(4

%)

WestOK

 

 

393.1

 

 

 

 

487.0

 

 

 

 

(93.9

)

 

 

(19

%)

Total Central

 

 

1,287.8

 

 

 

 

1,448.1

 

 

 

 

(160.3

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Badlands (5)

 

 

46.0

 

 

 

 

53.7

 

 

 

 

(7.7

)

 

 

(14

%)

Total Field

 

 

2,483.9

 

 

 

 

2,537.4

 

 

 

 

(53.5

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Coastal

 

 

758.2

 

 

 

 

868.6

 

 

 

 

(110.4

)

 

 

(13

%)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

3,242.1

 

 

 

 

3,406.0

 

 

 

 

(163.9

)

 

 

(5

%)

Gross NGL production, MBbl/d (3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SAOU (4)

 

 

33.3

 

 

 

 

29.2

 

 

 

 

4.1

 

 

 

14

%

WestTX

 

 

69.5

 

 

 

 

52.4

 

 

 

 

17.1

 

 

 

33

%

Total Permian Midland

 

 

102.8

 

 

 

 

81.6

 

 

 

 

21.2

 

 

 

 

 

Sand Hills (4)

 

 

14.8

 

 

 

 

15.7

 

 

 

 

(0.9

)

 

 

(6

%)

Versado

 

 

23.1

 

 

 

 

21.9

 

 

 

 

1.2

 

 

 

5

%

Total Permian Delaware

 

 

37.9

 

 

 

 

37.6

 

 

 

 

0.3

 

 

 

 

 

Total Permian

 

 

140.7

 

 

 

 

119.2

 

 

 

 

21.5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SouthTX

 

 

16.6

 

 

 

 

23.1

 

 

 

 

(6.5

)

 

 

(28

%)

North Texas

 

 

32.0

 

 

 

 

35.7

 

 

 

 

(3.7

)

 

 

(10

%)

SouthOK

 

 

40.9

 

 

 

 

28.0

 

 

 

 

12.9

 

 

 

46

%

WestOK

 

 

22.8

 

 

 

 

26.9

 

 

 

 

(4.1

)

 

 

(15

%)

Total Central

 

 

112.3

 

 

 

 

113.7

 

 

 

 

(1.4

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Badlands

 

 

5.5

 

 

 

 

7.6

 

 

 

 

(2.1

)

 

 

(28

%)

Total Field

 

 

258.5

 

 

 

 

240.5

 

 

 

 

18.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Coastal

 

 

33.3

 

 

 

 

44.2

 

 

 

 

(10.9

)

 

 

(25

%)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

291.8

 

 

 

 

284.7

 

 

 

 

7.1

 

 

 

2

%

Crude oil gathered, Badlands, MBbl/d

 

 

113.5

 

 

 

 

108.1

 

 

 

 

5.4

 

 

 

5

%

Crude oil gathered, Permian, MBbl/d (4)

 

 

9.2

 

 

 

 

 

 

 

 

9.2

 

 

 

 

Natural gas sales, BBtu/d (3)

 

 

1,562.2

 

 

 

 

1,687.2

 

 

 

 

(125.0

)

 

 

(7

%)

NGL sales, MBbl/d (3)

 

 

227.6

 

 

 

 

219.3

 

 

 

 

8.3

 

 

 

4

%

Condensate sales, MBbl/d

 

 

10.7

 

 

 

 

9.5

 

 

 

 

1.2

 

 

 

13

%

Average realized prices (6):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas, $/MMBtu

 

 

2.86

 

 

 

 

1.75

 

 

 

 

1.11

 

 

 

63

%

NGL, $/gal

 

 

0.50

 

 

 

 

0.28

 

 

 

 

0.22

 

 

 

79

%

Condensate, $/Bbl

 

 

44.98

 

 

 

 

25.65

 

 

 

 

19.33

 

 

 

75

%

 

(1)

Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter.

(2)

Plant natural gas inlet represents our undivided interest in the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.

(3)

Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales and NGL sales exclude producer take-in-kind volumes.

40


 

(4)

Includes operations from the Permian Acquisition for the period effective March 1, 2017. New Midland volumes are included within SAOU and New Delaware volumes are included within Sand Hills. For the volume statistics presented, the numerator is the total volume sold during the period of our ownership whi le the denominator is the number of calendar days during the quarter.

(5)

Badlands natural gas inlet represents the total wellhead gathered volume.

(6)

Average realized prices exclude the impact of hedging activities presented in Other.

 

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:

 

 

 

Three Months Ended March 31, 2017

 

Operating statistics:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Plant natural gas inlet, MMcf/d (1),(2)

 

Gross Volume (3)

 

 

Ownership %

 

 

Net Volume (3)

 

 

Actual Reported

 

SAOU (4)

 

 

275.6

 

 

 

100

%

 

 

275.6

 

 

 

275.6

 

WestTX (5) (6)

 

 

736.9

 

 

 

73

%

 

 

536.5

 

 

 

536.5

 

Total Permian Midland

 

 

1,012.5

 

 

 

 

 

 

 

812.1

 

 

 

812.1

 

Sand Hills (4)

 

 

139.5

 

 

 

100

%

 

 

139.5

 

 

 

139.5

 

Versado (7)

 

 

198.5

 

 

 

100

%

 

 

198.5

 

 

 

198.5

 

Total Permian Delaware

 

 

338.0

 

 

 

 

 

 

 

338.0

 

 

 

338.0

 

Total Permian

 

 

1,350.5

 

 

 

 

 

 

 

1,150.1

 

 

 

1,150.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SouthTX

 

 

171.8

 

 

Varies (8)

 

 

 

161.6

 

 

 

171.8

 

North Texas

 

 

282.5

 

 

 

100

%

 

 

282.5

 

 

 

282.5

 

SouthOK

 

 

440.4

 

 

Varies (9)

 

 

 

366.1

 

 

 

440.4

 

WestOK

 

 

393.1

 

 

 

100

%

 

 

393.1

 

 

 

393.1

 

Total Central

 

 

1,287.8

 

 

 

 

 

 

 

1,203.3

 

 

 

1,287.8

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Badlands (10)

 

 

46.0

 

 

 

100

%

 

 

46.0

 

 

 

46.0

 

Total Field

 

 

2,684.3

 

 

 

 

 

 

 

2,399.4

 

 

 

2,483.9

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross NGL production, MBbl/d (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SAOU (4)

 

 

33.3

 

 

 

100

%

 

 

33.3

 

 

 

33.3

 

WestTX (5) (6)

 

 

95.5

 

 

 

73

%

 

 

69.5

 

 

 

69.5

 

Total Permian Midland

 

 

128.8

 

 

 

 

 

 

 

102.8

 

 

 

102.8

 

Sand Hills (4)

 

 

14.8

 

 

 

100

%

 

 

14.8

 

 

 

14.8

 

Versado (7)

 

 

23.1

 

 

 

100

%

 

 

23.1

 

 

 

23.1

 

Total Permian Delaware

 

 

37.9

 

 

 

 

 

 

 

37.9

 

 

 

37.9

 

Total Permian

 

 

166.7

 

 

 

 

 

 

 

140.7

 

 

 

140.7

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SouthTX

 

 

16.6

 

 

Varies (8)

 

 

 

15.7

 

 

 

16.6

 

North Texas

 

 

32.0

 

 

 

100

%

 

 

32.0

 

 

 

32.0

 

SouthOK

 

 

40.9

 

 

Varies (9)

 

 

 

34.2

 

 

 

40.9

 

WestOK

 

 

22.8

 

 

 

100

%

 

 

22.8

 

 

 

22.8

 

Total Central

 

 

112.3

 

 

 

 

 

 

 

104.7

 

 

 

112.3

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Badlands

 

 

5.5

 

 

 

100

%

 

 

5.5

 

 

 

5.5

 

Total Field

 

 

284.5

 

 

 

 

 

 

 

250.9

 

 

 

258.5

 

 

(1)

Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.

(2)

Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes.

41


 

(3)

For these volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter.

(4)

Includes operations from the Permian Acquisition for the period effective March 1, 2017. New Midland volumes are included within SAOU and New Delaware volumes are included within Sand Hills.

(5)

Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.

(6)

Includes the Buffalo Plant that commenced commercial operations in April 2016.

(7)

Versado is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials. We held a 63% interest in Versado until October 31, 2016, when we acquired the remaining 37% interest.

(8)

SouthTX includes the Silver Oak II plant, of which Targa Pipeline Partners, L.P. (“TPL”) has owned a 90% interest since October 2015, and prior to which TPL owned a 100% interest. Silver Oak II is owned by a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.

(9)

SouthOK includes the Centrahoma joint venture, of which TPL owns 60%, and other plants which are owned 100% by TPL. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.

(10)

Badlands natural gas inlet represents the total wellhead gathered volume.

 

 

 

Three Months Ended March 31, 2016

 

Operating statistics:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Plant natural gas inlet, MMcf/d (1),(2)

 

Gross Volume (3)

 

 

Ownership %

 

 

Net Volume (3)

 

 

Actual Reported

 

SAOU

 

 

243.5

 

 

 

100

%

 

 

243.5

 

 

 

243.5

 

WestTX (4)

 

 

633.2

 

 

 

73

%

 

 

461.0

 

 

 

461.0

 

Total Permian Midland

 

 

876.7

 

 

 

 

 

 

 

704.5

 

 

 

704.5

 

Sand Hills

 

 

151.1

 

 

 

100

%

 

 

151.1

 

 

 

151.1

 

Versado (5)

 

 

180.0

 

 

 

63

%

 

 

113.4

 

 

 

180.0

 

Total Permian Delaware

 

 

331.1

 

 

 

 

 

 

 

264.5

 

 

 

331.1

 

Total Permian

 

 

1,207.8

 

 

 

 

 

 

 

969.0

 

 

 

1,035.6

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SouthTX

 

 

175.7

 

 

 

100

%

 

 

175.7

 

 

 

175.7

 

North Texas

 

 

327.5

 

 

 

100

%

 

 

327.5

 

 

 

327.5

 

SouthOK

 

 

457.9

 

 

Varies (6)

 

 

 

380.9

 

 

 

457.9

 

WestOK

 

 

487.0

 

 

 

100

%

 

 

487.0

 

 

 

487.0

 

Total Central

 

 

1,448.1

 

 

 

 

 

 

 

1,371.1

 

 

 

1,448.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Badlands (7)

 

 

53.7

 

 

 

100

%

 

 

53.7

 

 

 

53.7

 

Total Field

 

 

2,709.6

 

 

 

 

 

 

 

2,393.8

 

 

 

2,537.4

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross NGL production, MBbl/d (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SAOU

 

 

29.2

 

 

 

100

%

 

 

29.2

 

 

 

29.2

 

WestTX (4)

 

 

72.0

 

 

 

73

%

 

 

52.4

 

 

 

52.4

 

Total Permian Midland

 

 

101.2

 

 

 

 

 

 

 

81.6

 

 

 

81.6

 

Sand Hills

 

 

15.7

 

 

 

100

%

 

 

15.7

 

 

 

15.7

 

Versado (5)

 

 

21.9

 

 

 

63

%

 

 

13.8

 

 

 

21.9

 

Total Permian Delaware

 

 

37.6

 

 

 

 

 

 

 

29.5

 

 

 

37.6

 

Total Permian

 

 

138.8

 

 

 

 

 

 

 

111.1

 

 

 

119.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SouthTX

 

 

23.1

 

 

 

100

%

 

 

23.1

 

 

 

23.1

 

North Texas

 

 

35.7

 

 

 

100

%

 

 

35.7

 

 

 

35.7

 

SouthOK

 

 

28.0

 

 

Varies (6)

 

 

 

24.7

 

 

 

28.0

 

WestOK

 

 

26.9

 

 

 

100

%

 

 

26.9

 

 

 

26.9

 

Total Central

 

 

113.7

 

 

 

 

 

 

 

110.4

 

 

 

113.7

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Badlands

 

 

7.6

 

 

 

100

%

 

 

7.6

 

 

 

7.6

 

Total Field

 

 

260.1

 

 

 

 

 

 

 

229.1

 

 

 

240.5

 

 

(1)

Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.

(2)

Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes.

(3)

For these volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter.

(4)

Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.

(5)

Versado is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials. We held a 63% interest in Versado until October 31, 2016, when we acquired the remaining 37% interest.

(6)

SouthOK includes the Centrahoma joint venture, of which TPL owns 60%, and other plants which are owned 100% by TPL. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.

(7)

Badlands natural gas inlet represents the total wellhead gathered volume.

42


 

Logistics and Marketing Segment

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

2017

 

 

2016

 

 

2017 vs. 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(In millions)

 

Gross margin

 

$

 

196.4

 

 

$

 

210.6

 

 

$

 

(14.2

)

 

 

(7

%)

Operating expenses

 

 

 

66.3

 

 

 

 

53.6

 

 

 

 

12.7

 

 

 

24

%

Operating margin

 

$

 

130.1

 

 

$

 

157.0

 

 

$

 

(26.9

)

 

 

(17

%)

Operating statistics MBbl/d (1):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fractionation volumes (2)(3)

 

 

 

304.9

 

 

 

 

295.5

 

 

 

 

9.4

 

 

 

3

%

LSNG treating volumes (2)

 

 

 

34.5

 

 

 

 

21.0

 

 

 

 

13.5

 

 

 

64

%

Benzene treating volumes (2)

 

 

 

23.5

 

 

 

 

21.0

 

 

 

 

2.5

 

 

 

12

%

Export volumes, MBbl/d (4)

 

 

 

217.5

 

 

 

 

181.0

 

 

 

 

36.5

 

 

 

20

%

NGL sales, MBbl/d

 

 

 

502.0

 

 

 

 

482.0

 

 

 

 

20.0

 

 

 

4

%

Average realized prices:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NGL realized price, $/gal

 

$

 

0.66

 

 

$

 

0.41

 

 

$

 

0.25

 

 

 

61

%

________________________________________________________

(1)

Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter.

(2)

Fractionation and treating contracts include pricing terms composed of base fees and fuel and power components which vary with the cost of energy.  As such, the Logistics and Marketing segment results include effects of variable energy costs that impact both gross margin and operating expenses.

(3)

Fractionation volumes reflect those volumes delivered and settled under fractionation contracts.

(4)

Export volumes represent the quantity of NGL products delivered to third-party customers at our Galena Park Marine Terminal that are destined for international markets.

 

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

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

2017

 

 

2016

 

 

2017 vs. 2016

 

 

 

(In millions)

 

Gross margin

 

$

(1.0

)

 

$

26.8

 

 

$

(27.8

)

Operating margin

 

$

(1.0

)

 

$

26.8

 

 

$

(27.8

)

 

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.

 

43


 

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

 

 

 

Three Months Ended March 31, 2017

 

 

Three Months Ended March 31, 2016

 

 

 

 

 

 

 

(In millions, except volumetric data and price amounts)

 

 

 

 

 

 

 

Volume

Settled

 

 

Price

Spread

(1)

 

 

Gain

(Loss)

 

 

Volume

Settled

 

 

Price

Spread

(1)

 

 

Gain

(Loss)

 

 

2017 vs. 2016

 

Natural gas (BBtu)

 

 

10.5

 

 

$

0.02

 

 

$

0.2

 

 

 

9.5

 

 

$

1.40

 

 

$

13.2

 

 

$

(13.0

)

NGL (MMgal)

 

 

43.3

 

 

 

(0.04

)

 

 

(1.8

)

 

 

14.3

 

 

 

0.27

 

 

 

3.8

 

 

 

(5.6

)

Crude oil (MBbl)

 

 

0.2

 

 

 

5.35

 

 

 

1.2

 

 

 

0.2

 

 

 

35.22

 

 

 

7.1

 

 

 

(5.9

)

Non-hedge accounting (2)

 

 

 

 

 

 

 

 

 

 

(0.8

)

 

 

 

 

 

 

 

 

 

 

2.7

 

 

 

(3.5

)

Ineffectiveness (3)

 

 

 

 

 

 

 

 

 

 

0.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

0.2

 

 

 

 

 

 

 

 

 

 

 

$

(1.0

)

 

 

 

 

 

 

 

 

 

$

26.8

 

 

$

(27.8

)

 

(1)

The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.

(2)

Mark-to-market income (loss) associated with derivative contracts that are not designated as hedges for accounting purposes.

(3)

Ineffectiveness primarily relates to certain crude hedging contracts and certain acquired hedges of TPL that do not qualify for hedge accounting.

 

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.

44


 

Short-term Liquidity

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

 

 

 

 

May 1, 2017

 

 

 

 

(In millions)

 

Cash on hand

 

$

113.6

 

Total availability under the TRP Revolver

 

 

1,600.0

 

Total availability under the Securitization Facility

 

 

250.2

 

 

 

 

1,963.8

 

 

 

 

 

 

Less:

Outstanding borrowings under the TRP Revolver

 

 

(180.0

)

 

Outstanding borrowings under the Securitization Facility

 

 

(250.2

)

 

Outstanding letters of credit under the TRP Revolver

 

 

(20.2

)

 

Total liquidity

 

$

1,513.4

 

 

Other potential capital resources associated with our existing arrangements include:

 

Our right to request an additional $500 million in commitment increases under the TRP Revolver, subject to the terms therein. The TRP Revolver matures on October 7, 2020.

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.

45


 

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.

46


 

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

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

2017

 

 

2016

 

 

2017 vs. 2016

 

 

 

(In millions)

 

Cash flows from operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

Cash received from customers

 

$

2,243.2

 

 

$

1,483.8

 

 

$

759.4

 

Cash received from (paid to) derivative counterparties

 

 

1.2

 

 

 

28.1

 

 

 

(26.9

)

Cash distributions from equity investments (1)

 

 

2.7

 

 

 

 

 

 

2.7

 

Cash outlays for:

 

 

 

 

 

 

 

 

 

 

 

 

Product purchases

 

 

1,646.0

 

 

 

1,022.4

 

 

 

623.6

 

Operating expenses

 

 

169.2

 

 

 

120.9

 

 

 

48.3

 

General and administrative expense

 

 

58.9

 

 

 

48.3

 

 

 

10.6

 

      Interest paid, net of amounts capitalized (2)

 

 

53.5

 

 

 

77.3

 

 

 

(23.8

)

      Income taxes paid, net of refunds

 

 

(0.1

)

 

 

1.1

 

 

 

(1.2

)

Other cash (receipts) payments

 

 

6.4

 

 

 

(0.1

)

 

 

6.5

 

Net cash provided by operating activities

 

$

313.2

 

 

$

242.0

 

 

$

71.2

 

 

(1)

Excludes $3.4 million included in investing activities for the three months ended March 31, 2016 related to distributions from GCF and the T2 Joint Ventures that exceeded cumulative equity earnings. We did not have distributions that exceeded cumulative earnings for the three months ended March 31, 2017.

(2)

Net of capitalized interest paid of $1.7 million and $4.8 million included in investing activities for the three months ended March 31, 2017 and 2016.

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

 

Three Months Ended March 31,

 

 

 

 

 

2017

 

 

2016

 

 

2017 vs. 2016

 

(In millions)

 

$

(625.5

)

 

$

(188.0

)

 

$

(437.5

)

 

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

 

 

Three Months Ended March 31,

 

 

2017

 

 

2016

 

Source of Financing Activities, net

(In millions)

 

Debt, including financing costs

$

(140.1

)

 

$

(679.9

)

Equity offerings, net of financing costs

 

-

 

 

 

(7.5

)

Distributions

 

(198.1

)

 

 

(203.5

)

Contributions from TRC and General Partner

 

655.0

 

 

 

801.0

 

Other

 

(0.8

)

 

 

3.8

 

Net cash provided by (used in) financing activities

$

316.0

 

 

$

(86.1

)

 

47


 

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.

Three Months

 

Date Paid

 

Total

 

 

Distributions   to

Targa   Resources

 

Ended

 

Or to Be Paid

 

Distributions

 

 

Corp.

 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2017

 

May 11, 2017

$

 

209.6

 

$

 

206.8

 

December 31, 2016

 

February 10, 2017

 

 

198.1

 

 

 

195.3

 

 

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.

 

 

Three Months Ended March 31,

 

 

 

2017

 

 

2016

 

Capital expenditures :

 

(In millions)

 

Consideration for business acquisition

 

$

1,032.4

 

 

$

 

Contingent consideration (1)

 

 

(461.6

)

 

 

 

Purchase consideration payable (2)

 

 

(90.0

)

 

 

 

Business acquisition, net of cash acquired

 

 

480.8

 

 

 

 

Expansion

 

 

148.9

 

 

 

161.9

 

Maintenance

 

 

25.7

 

 

 

15.0

 

Gross capital expenditures

 

 

174.6

 

 

 

176.9

 

Transfers from materials and supplies inventory to

   property, plant and equipment

 

 

(0.4

)

 

 

(0.5

)

Decrease in capital project payables and accruals

 

 

(30.0

)

 

 

13.7

 

Cash outlays for capital projects

 

 

144.2

 

 

 

190.1

 

Total

 

$

625.0

 

 

$

190.1

 

48


 

 

 

(1)

See Note 4 – Business Acquisitions and Divestitures of the “Consolidated Financial Statements.” Represents the preliminary estimated fair value of contingent consideration at the acquisition date.

 

(2)

The payable will be settled in cash within 90 days from March 1, 2017.

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

49


 

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 transa ctions 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


 

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

Natural GAS

 

Instrument

 

Price

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Type

Index

$/MMBtu

 

 

 

 

MMBtu/d

 

 

Fair Value

 

 

 

 

 

 

 

 

 

2017

 

 

2018

 

 

2019

 

 

(In millions)

 

Gathering & Processing

 

Swap

IF-Waha

 

2.87

 

 

 

 

 

103,600

 

 

 

-

 

 

 

-

 

 

 

(2.0

)

Swap

IF-Waha

 

2.68

 

 

 

 

 

-

 

 

 

73,600

 

 

 

-

 

 

 

3.7

 

Swap

IF-Waha

 

2.77

 

 

 

 

 

-

 

 

 

-

 

 

 

45,383

 

 

 

6.5

 

 

 

 

 

 

 

 

 

 

103,600

 

 

 

73,600

 

 

 

45,383

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Swap

IF-PB

 

2.51

 

 

 

 

 

10,900

 

 

 

-

 

 

 

-

 

 

 

(1.0

)

Swap

IF-PB

 

2.51

 

 

 

 

 

-

 

 

 

10,900

 

 

 

-

 

 

 

0.3

 

 

 

 

 

 

 

 

 

 

10,900

 

 

 

10,900

 

 

 

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Swap

IF-PEPL

 

2.6835

 

 

 

 

 

16,000

 

 

 

-

 

 

 

-

 

 

 

(1.1

)

Swap

IF-PEPL

 

2.6835

 

 

 

 

 

-

 

 

 

16,000

 

 

 

-

 

 

 

0.4

 

Swap

IF-PEPL

 

2.6835

 

 

 

 

 

-

 

 

 

-

 

 

 

16,000

 

 

 

1.6

 

 

 

 

 

 

 

 

 

 

16,000

 

 

 

16,000

 

 

 

16,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Swap

NG-NYMEX

 

3.99

 

 

 

 

 

12,000

 

 

 

-

 

 

 

-

 

 

 

2.3

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Put Price

 

Call Price

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Collar

IF-Waha

 

3.00

 

 

3.67

 

 

7,500

 

 

 

-

 

 

 

-

 

 

 

0.4

 

Collar

IF-Waha

 

3.25

 

 

4.20

 

 

-

 

 

 

1,849

 

 

 

-

 

 

 

0.2

 

 

 

 

 

 

 

 

 

 

7,500

 

 

 

1,849

 

 

 

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Put Price

 

Call Price

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Collar

IF-PB

 

2.80

 

 

3.50

 

 

15,400

 

 

 

-

 

 

 

-

 

 

 

0.6

 

Collar

IF-PB

 

3.00

 

 

3.65

 

 

-

 

 

 

7,637

 

 

 

-

 

 

 

1.4

 

 

 

 

 

 

 

 

 

 

15,400

 

 

 

7,637

 

 

 

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis Swap

EP-PERMIAN

 

(0.1444

)

 

 

 

 

6,000

 

 

 

-

 

 

 

-

 

 

 

0.5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis Swap

PEPL

 

(0.3308

)

 

 

 

 

6,000

 

 

 

-

 

 

 

-

 

 

 

0.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

        Gathering & Processing total

 

 

 

 

 

177,400

 

 

 

109,986

 

 

 

61,383

 

 

 

13.9

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other (1)

 

Swap

NG-NYMEX

 

(3.1602

)

 

 

 

 

(540

)

 

 

-

 

 

 

-

 

 

$

0.0

 

Basis Swap

Various

 

(0.1930

)

 

 

 

 

83,964

 

 

 

1,103

 

 

 

-

 

 

 

(1.2

)

Future

Various

 

3.2640

 

 

 

 

 

-

 

 

 

1,103

 

 

 

-

 

 

 

(0.1

)

        Other total

 

 

 

 

 

83,424

 

 

 

2,206

 

 

 

-

 

 

$

(1.3

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

12.6

 

 

(1)

Other includes derivative agreements entered into for the purpose of hedging future commodity purchases and sales in our Logistics and Marketing segment.

51


 

NGLs

 

Instrument

 

Price

 

 

 

 

 

 

 

 

 

 

Type

Index

$/gal

 

 

 

 

Bbl/d

 

 

Fair Value

 

 

 

 

 

 

 

 

 

2017

 

 

2018

 

 

2019

 

 

(In millions)

 

Gathering & Processing

 

Swap

C2-OPIS-MB

 

0.2746

 

 

 

 

 

4,498

 

 

 

-

 

 

 

-

 

 

 

0.8

 

Swap

C2-OPIS-MB

 

0.2776

 

 

 

 

 

-

 

 

 

2,368

 

 

 

-

 

 

 

(1.0

)

Swap

C2-OPIS-MB

 

0.2932

 

 

 

 

 

-

 

 

 

-

 

 

 

1,710

 

 

 

(1.0

)

Total

 

 

 

 

 

 

 

 

4,498

 

 

 

2,368

 

 

 

1,710

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Swap

C3-OPIS-MB

 

0.6505

 

 

 

 

 

6,005

 

 

 

-

 

 

 

-

 

 

 

2.2

 

Swap

C3-OPIS-MB

 

0.5530

 

 

 

 

 

-

 

 

 

2,650

 

 

 

-

 

 

 

(1.3

)

Swap

C3-OPIS-MB

 

0.5530

 

 

 

 

 

-

 

 

 

-

 

 

 

2,650

 

 

 

(0.1

)

Total

 

 

 

 

 

 

 

 

6,005

 

 

 

2,650

 

 

 

2,650

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Swap

IC4-OPIS-MB

 

0.8080

 

 

 

 

 

630

 

 

 

-

 

 

 

-

 

 

 

0.2

 

Swap

IC4-OPIS-MB

 

0.7487

 

 

 

 

 

-

 

 

 

230

 

 

 

-

 

 

 

0.0

 

Swap

IC4-OPIS-MB

 

0.7200

 

 

 

 

 

-

 

 

 

-

 

 

 

110

 

 

 

(0.0

)

Total

 

 

 

 

 

 

 

 

630

 

 

 

230

 

 

 

110

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Swap

NC4-OPIS-MB

 

0.7960

 

 

 

 

 

1,500

 

 

 

-

 

 

 

-

 

 

 

0.5

 

Swap

NC4-OPIS-MB

 

0.7388

 

 

 

 

 

-

 

 

 

600

 

 

 

-

 

 

 

0.2

 

Swap

NC4-OPIS-MB

 

0.7050

 

 

 

 

 

-

 

 

 

-

 

 

 

300

 

 

 

(0.0

)

Total

 

 

 

 

 

 

 

 

1,500

 

 

 

600

 

 

 

300

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Swap

C5-OPIS-MB

 

1.1056

 

 

 

 

 

1,510

 

 

 

-

 

 

 

-

 

 

 

(0.6

)

Swap

C5-OPIS-MB

 

1.0385

 

 

 

 

 

-

 

 

 

810

 

 

 

-

 

 

 

(0.7

)

Swap

C5-OPIS-MB

 

1.0825

 

 

 

 

 

-

 

 

 

-

 

 

 

569

 

 

 

0.3

 

Total

 

 

 

 

 

 

 

 

1,510

 

 

 

810

 

 

 

569

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Put Price

 

Call Price

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Collar

C2-OPIS-MB

 

0.240

 

 

0.290

 

 

410

 

 

 

-

 

 

 

-

 

 

 

0.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Put Price

 

Call Price

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Collar

C3-OPIS-MB

 

0.570

 

 

0.68625

 

 

380

 

 

 

-

 

 

 

-

 

 

 

0.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Put Price

 

Call Price

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Collar

C5-OPIS-MB

 

1.210

 

 

1.415

 

 

130

 

 

 

-

 

 

 

-

 

 

 

0.2

 

Collar

C5-OPIS-MB

 

1.230

 

 

1.385

 

 

-

 

 

 

32

 

 

 

-

 

 

 

0.1

 

Total

 

 

 

 

 

 

 

 

130

 

 

 

32

 

 

 

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

        Gathering & Processing total

 

 

 

 

 

15,063

 

 

 

6,690

 

 

 

5,339

 

 

$

(0.2

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other (1)(2)

 

Future

C2-OPIS-MB

 

0.2715

 

 

 

 

 

4,091

 

 

 

-

 

 

 

-

 

 

 

(0.1

)

Future

C2-OPIS-MB

 

0.3015

 

 

 

 

 

-

 

 

 

1,288

 

 

 

-

 

 

 

(0.2

)

Total

 

 

 

 

 

 

 

 

4,091

 

 

 

1,288

 

 

 

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future

C3-OPIS-MB

 

0.6618

 

 

 

 

 

1,400

 

 

 

-

 

 

 

-

 

 

 

0.4

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future

IC4-OPIS-MB

 

0.7800

 

 

 

 

 

218

 

 

 

-

 

 

 

-

 

 

 

(0.0

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future

Heating Oil

 

1.5950

 

 

 

 

 

(7)

 

 

 

-

 

 

 

-

 

 

 

(0.0

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Put Price

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Option

C2-OPIS-MB

 

0.2694

 

 

 

 

 

727

 

 

 

-

 

 

 

-

 

 

 

0.2

 

Option

C2-OPIS-MB

 

0.2963

 

 

 

 

 

-

 

 

 

1,644

 

 

 

-

 

 

 

0.8

 

Total

 

 

 

 

 

 

 

 

727

 

 

 

1,644

 

 

 

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

        Other total

 

 

 

 

 

6,429

 

 

 

2,932

 

 

 

-

 

 

$

1.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

0.9

 

52


 

 

(1)

Other includes derivative agreements entered into for the purpose of hedging future commodity purchases and sales in our Logistics and Marketing segment.

(2)

The “Future” line items are comprised of futures transactions entered into on both the Intercontinental Exchange (“ICE”) and Chicago Mercantile Exchange (“CME”).

CONDENSATE

 

Instrument

 

Price

 

 

 

 

 

 

 

 

 

 

Type

Index

$/Bbl

 

 

 

 

Bbl/d

 

 

Fair Value

 

 

 

 

 

 

 

 

 

2017

 

 

2018

 

 

2019

 

 

(In millions)

 

Gathering & Processing

 

Swap

WTI-NYMEX

 

54.54

 

 

 

 

 

2,690

 

 

 

-

 

 

 

-

 

 

 

2.1

 

Swap

WTI-NYMEX

 

48.79

 

 

 

 

 

-

 

 

 

2,190

 

 

 

-

 

 

 

(2.4

)

Swap

WTI-NYMEX

 

51.19

 

 

 

 

 

-

 

 

 

-

 

 

 

1,063

 

 

 

(0.1

)

 

 

 

 

 

 

 

 

 

2,690

 

 

 

2,190

 

 

 

1,063

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Put Price

 

Call Price

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Collar

WTI-NYMEX

 

54.04

 

 

64.09

 

 

1,380

 

 

 

-

 

 

 

-

 

 

 

1.7

 

Collar

WTI-NYMEX

 

49.76

 

 

58.50

 

 

-

 

 

 

691

 

 

 

-

 

 

 

0.4

 

Collar

WTI-NYMEX

 

48.00

 

 

56.25

 

 

-

 

 

 

-

 

 

 

590

 

 

 

0.2

 

 

 

 

 

 

 

 

 

 

1,380

 

 

 

691

 

 

 

590

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

 

4,070

 

 

 

2,881

 

 

 

1,653

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1.9

 

 

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


 

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 receipt s 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 c ounterparties 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 m illion, 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


 

PART II – OTHE R 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


 

 

I tem 6. Exhibits.

 

Number

 

Description

 

 

 

2.1***

 

Membership Interest Purchase and Sale Agreement, dated January 22, 2017, by and between Targa Resources Partners LP and Outrigger Delaware Midstream, LLC (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 23, 2017 (File No. 001-33303)).

 

 

 

2.2***

 

Membership Interest Purchase and Sale Agreement, dated January 22, 2017, by and between Targa Resources Partners LP and Outrigger Energy, LLC (incorporated by reference to Exhibit 2.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 23, 2017 (File No. 001-33303)).

 

 

 

2.3***

 

Membership Interest Purchase and Sale Agreement, dated January 22, 2017, by and between Targa Resources Partners LP and Outrigger Midland Midstream, LLC (incorporated by reference to Exhibit 2.3 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 23, 2017 (File No. 001-33303)).

 

 

 

3.1

 

Certificate of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.2 to Targa Resources Partners LP’s Registration Statement on Form S-1 filed November 16, 2006 (File No. 333-138747)).

 

 

 

3.2

 

Certificate of Formation of Targa Resources GP LLC (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).

 

 

 

3.3

 

Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP, effective December 1, 2016 (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 21, 2016 (File No. 001-33303)).

 

 

 

3.4

 

Limited Liability Company Agreement of Targa Resources GP LLC (incorporated by reference to Exhibit 3.4 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).

 

 

 

4.1

 

Specimen Unit Certificate for the Series A Preferred Units (attached as Exhibit B to the Second Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP and incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 15, 2015 (File No. 001-33303)).

 

 

 

4.2*

 

Supplemental Indenture dated March 10, 2017 to Indenture dated January 31, 2012, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

 

 

 

4.3*

 

Supplemental Indenture dated March 10, 2017 to Indenture dated October 25, 2012, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

 

 

 

4.4*

 

Supplemental Indenture dated March 10, 2017 to Indenture dated May 14, 2013, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

 

 

 

4.5*

 

Supplemental Indenture dated March 10, 2017 to Indenture dated October 28, 2014, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

 

 

 

4.6*

 

Supplemental Indenture dated March 10, 2017 to Indenture dated January 30, 2015, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

 

 

 

4.7*

 

Supplemental Indenture dated March 10, 2017 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

 

 

 

4.8*

 

Supplemental Indenture dated March 10, 2017 to Indenture dated October 6, 2016, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

 

 

 

56


 

Number

 

Description

 

 

 

10.1

 

Commitment Increase Request, dated February 23, 2017, by and among Targa Receivables LLC, as seller, the Partnership, as servicer, and PNC Bank, National Association, as administrator, purchaser agent and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 24, 2017 (File No. 001-33303)).

 

 

 

10.2

 

Indemnification Agreement by and between Targa Resources Corp. and Robert Muraro, dated February 22, 2017 (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed February 27, 2017 (File No. 001-34991)).

 

 

 

10.3+

 

Targa Resources Corp. 2017 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Targa Resources Partner’s Current Report on Form 8-K filed January 25, 2017(File No. 001-33303)).

 

 

 

31.1*

 

Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

 

 

31.2*

 

Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

 

 

32.1**

 

Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

 

32.2**

 

Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

 

101.INS*

 

XBRL Instance Document

 

 

 

101.SCH*

 

XBRL Taxonomy Extension Schema Document

 

 

 

101.CAL*

 

XBRL Taxonomy Extension Calculation Linkbase Document

 

 

 

101.DEF*

 

XBRL Taxonomy Extension Definition Linkbase Document

 

 

 

101.LAB*

 

XBRL Taxonomy Extension Label Linkbase Document

 

 

 

101.PRE*

 

XBRL Taxonomy Extension Presentation Linkbase Document

 

*

Filed herewith

**

Furnished herewith

***

The schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K and will be provided to the Securities and Exchange Commission upon request.

+

Management contract or compensatory plan or arrangement

 

 


57


 

SIGNA TURES

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.

 

 

Targa Resources Partners LP

(Registrant)

 

 

 

 

By:

Targa Resources GP LLC,

 

 

its general partner

 

 

 

Date: May 4, 2017

By:

/s/ Matthew J. Meloy

 

 

Matthew J. Meloy

 

 

Executive Vice President and Chief Financial Officer

 

 

(Authorized Officer and Principal Financial Officer)

 

 

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

 

Title:

Vice President and Treasurer


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

 

Title:

Vice President and Treasurer

 

 

TARGA RESOURCES PARTNERS FINANCE CORPORATION

 

 

By:   /s/ Chris McEwan

Name: Chris McEwan

 

Title:

Vice President and Treasurer

 


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

 

Title:

Vice President and Treasurer

 

TARGA RESOURCES PARTNERS FINANCE CORPORATION

 

 

By:   /s/ Chris McEwan

Name: Chris McEwan

 

Title:

Vice President and Treasurer

 


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

 

Title:

Vice President and Treasurer

 

 

TARGA RESOURCES PARTNERS FINANCE CORPORATION

 

 

By:   /s/ Chris McEwan

Name: Chris McEwan

 

Title:

Vice President and Treasurer

 


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)


 

ISSUERS

 

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

 

 

By:   /s/ Chris McEwan

Name: Chris McEwan

 

Title:

Vice President and Treasurer

 

TARGA RESOURCES PARTNERS FINANCE CORPORATION

 

 

By:   /s/ Chris McEwan

Name: Chris McEwan

 

Title:

Vice President and Treasurer

 

 


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


 

TRUSTEE

 

U.S. BANK NATIONAL ASSOCIATION ,

as Trustee

 

 

By:   /s/ Shazia Flores

Authorized Signatory

 

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

Exhibit 4.6

 

#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)


 

ISSUE RS

 

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

 

 

By:   /s/ Chris McEwan

Name: Chris McEwan

 

Title:

Vice President and Treasurer

 

 

 

TARGA RESOURCES PARTNERS FINANCE CORPORATION

 

 

By:   /s/ Chris McEwan

Name: Chris McEwan

 

Title:

Vice President and Treasurer

 


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


 

TRUSTEE

 

U.S. BANK NATIONAL ASSOCIATION ,

as Trustee

 

 

By:   /s/ Shazia Flores

Authorized Signatory

 

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

Exhibit 4.7

 

#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.

 


 

 

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.

 


 

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)


 

ISSUERS

 

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

 

 

By:   /s/ Chris McEwan

Name: Chris McEwan

 

Title:

Vice President and Treasurer

 

TARGA RESOURCES PARTNERS FINANCE CORPORATION

 

 

By:   /s/ Chris McEwan

Name: Chris McEwan

 

Title:

Vice President and Treasurer

 

 

 

 


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


 

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.

 


 

 

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.

 


 

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)


 

ISSUERS

 

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

 

 

By:   /s/ Chris McEwan

Name: Chris McEwan

 

Title:

Vice President and Treasurer

 

 

 

TARGA RESOURCES PARTNERS FINANCE CORPORATION

 

 

By:   /s/ Chris McEwan

Name: Chris McEwan

 

Title:

Vice President and Treasurer

 

 

 

 


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


 

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

 

By:

/s/ Joe Bob Perkins

Name:

Joe Bob Perkins

Title:

Chief Executive Officer

of Targa Resources GP LLC, the general partner of Targa Resources Partners LP

 

(Principal Executive Officer)

 

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

 

By:

/s/ Matthew J. Meloy

Name:

Matthew J. Meloy

Title:

Executive Vice President and Chief Financial Officer

of Targa Resources GP LLC, the general partner of Targa Resources Partners LP

 

(Principal Financial Officer)

 

 

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.

 

By:

/s/ Joe Bob Perkins

Name:

Joe Bob Perkins

Title:

Chief Executive Officer

of Targa Resources GP LLC, the general partner of Targa Resources Partners LP

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.

 

By:

/s/ Matthew J. Meloy

Name:

Matthew J. Meloy

Title:

Executive Vice President and Chief Financial Officer

of Targa Resources GP LLC, the general partner of Targa Resources Partners LP

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.