Attached files

file filename
EXCEL - IDEA: XBRL DOCUMENT - Targa Resources Partners LPFinancial_Report.xls
EX-12.1 - EXHIBIT 12.1 - Targa Resources Partners LPex12_1.htm
EX-32.2 - EXHIBIT 32.2 - Targa Resources Partners LPex32_2.htm
EX-31.1 - EXHIBIT 31.1 - Targa Resources Partners LPex31_1.htm
EX-32.1 - EXHIBIT 32.1 - Targa Resources Partners LPex32_1.htm
EX-31.2 - EXHIBIT 31.2 - Targa Resources Partners LPex31_2.htm

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, 2015

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 R 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 R No £
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer R
Accelerated filer £
Non-accelerated filer £
Smaller reporting company £

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes £ No R.
 
As of  May 1, 2015, there were 180,830,462 common units representing limited partner interest and 3,690,419 general partner units outstanding.
 



PART I—FINANCIAL INFORMATION
     
4
     
 
4
     
 
5
     
 
6
     
 
7
     
 
8
     
 
9
     
33
     
55
     
59
     
PART II—OTHER INFORMATION
     
60
     
60
     
60
     
60
     
60
     
60
     
61
     
SIGNATURES
     
63
 
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 by the use of forward-looking phrases, 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 risks set forth in “Part II – Other Information, Item 1A. Risk Factors.” in this Quarterly Report on Form 10-Q (“Quarterly Report”) as well as the following risks and uncertainties:

· our ability to access the debt and equity 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 risks;

· the level of creditworthiness of counterparties to various transactions;

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

· the timing and extent of changes in natural gas, natural gas liquids (“NGL”), crude oil and other commodity prices, interest rates and demand for our services;

· 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;

· 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 NGL supplies to our logistics and marketing facilities and our success in connecting our facilities to transportation and markets;

· our ability to grow through acquisitions or internal growth projects and the successful integration and future performance of such assets; including with respect to the Atlas mergers (as defined below) which were completed February 27, 2015 between Targa Resources Corp. (“Targa”, “Parent” or “TRC”) and Atlas Energy, L.P., a Delaware limited partnership (“ATLS”), and between Atlas Pipeline Partners L.P., a Delaware limited partnership (“APL”) and us;

· general economic, market and business conditions; and

· the risks described elsewhere in “Part II – Other Information, Item 1A. Risk Factors.” in this Quarterly Report, our Annual Report on Form 10-K for the year ended December 31, 2014 (“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 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.

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)
Bcf
Billion cubic feet
Btu
British thermal units, a measure of heating value
BBtu
Billion British thermal units
/d
Per day
/hr
Per hour
gal
U.S. gallons
GPM
Liquid volume equivalent expressed as gallons per 1000 cu. ft. of natural gas
LPG
Liquefied petroleum gas
MBbl
Thousand barrels
MMBbl
Million barrels
MMBtu
Million British thermal units
MMcf
Million cubic feet
NGL(s)
Natural gas liquid(s)
NYMEX
New York Mercantile Exchange
GAAP
Accounting principles generally accepted in the United States of America
LIBOR
London Interbank Offer Rate
NYSE
New York Stock Exchange
   
Price Index Definitions
 
IF-NGPL MC
Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
IF-PB
Inside FERC Gas Market Report, Permian Basin
IF-WAHA
Inside FERC Gas Market Report, West Texas WAHA
NY-WTI
NYMEX, West Texas Intermediate Crude Oil
OPIS-MB
Oil Price Information Service, Mont Belvieu, Texas
NG-NYMEX NYMEX, Natural Gas
 
PART I – FINANCIAL INFORMATION
 
Item 1. Financial Statements.
 
TARGA RESOURCES PARTNERS LP
CONSOLIDATED BALANCE SHEETS

           
March 31,
   
December 31,
 
           
2015
   
2014
 
                 
           
(Unaudited)
 
           
(In millions)
 
ASSETS
 
Current assets:
         
Cash and cash equivalents
   
$
63.5
   
$
72.3
 
Trade receivables, net of allowances of $0.0 million
     
667.9
     
566.8
 
Inventories
     
78.2
     
168.9
 
Assets from risk management activities
     
126.0
     
44.4
 
Other current assets
     
11.8
     
3.8
 
Total current assets
     
947.4
     
856.2
 
Property, plant and equipment
     
11,617.8
     
6,514.3
 
Accumulated depreciation
     
(1,784.9
)
   
(1,689.7
)
Property, plant and equipment, net
     
9,832.9
     
4,824.6
 
Goodwill
     
628.5
     
-
 
Intangible assets, net
     
1,602.4
     
591.9
 
Long-term assets from risk management activities
     
51.2
     
15.8
 
Investments in unconsolidated affiliates
     
322.9
     
50.2
 
Other long-term assets
     
54.3
     
38.5
 
Total assets
   
$
13,439.6
   
$
6,377.2
 
                 
LIABILITIES AND OWNERS' EQUITY
 
Current liabilities:
                 
Accounts payable and accrued liabilities
   
$
710.8
   
$
592.7
 
Accounts payable to Targa Resources Corp.
     
41.3
     
53.2
 
Accounts receivable securitization facility
     
197.9
     
182.8
 
Liabilities from risk management activities
     
0.6
     
5.2
 
Total current liabilities
     
950.6
     
833.9
 
Long-term debt
     
5,140.4
     
2,783.4
 
Long-term liabilities from risk management activities
     
1.8
     
-
 
Deferred income taxes
     
44.5
     
13.7
 
Other long-term liabilities
     
73.3
     
57.8
 
                         
Contingencies (see Note 16)
                 
                         
Owners' equity:
                 
Limited partners
 
Issued
   
Outstanding
     
4,960.1
     
2,384.1
 
March 31, 2015
   
178,564,012
     
178,484,485
                 
December 31, 2014
   
118,652,798
     
118,586,056
                 
General partner
     
133.5
     
78.6
 
March 31, 2015
   
3,642,543
     
3,642,543
                 
December 31, 2014
   
2,420,124
     
2,420,124
                 
Special general partner interest (see Note 2)
1,608.3
-
Receivables from unit issuances
     
(25.6
)
   
(1.0
)
Accumulated other comprehensive income (loss)
     
77.4
     
60.3
 
Treasury units at cost (79,527 units as of March 31, 2015, and 66,742 as of December 31, 2014)
     
(5.4
)
   
(4.8
)
                     
6,748.3
     
2,517.2
 
Noncontrolling interests in subsidiaries
     
480.7
     
171.2
 
Total owners' equity
     
7,229.0
     
2,688.4
 
Total liabilities and owners' equity
   
$
13,439.6
   
$
6,377.2
 

See notes to consolidated financial statements.
 
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS

   
Three Months Ended March 31,
 
   
2015
   
2014
 
   
(Unaudited)
 
   
(In millions, except per unit amounts)
 
         
Revenues
 
$
1,679.7
   
$
2,294.7
 
Costs and expenses:
               
Product purchases
   
1,268.3
     
1,915.1
 
Operating expenses
   
111.3
     
104.3
 
Depreciation and amortization expenses
   
119.6
     
79.5
 
General and administrative expenses
   
40.3
     
35.9
 
Other operating income (expense)
   
0.6
     
(0.7
)
Income from operations
   
139.6
     
160.6
 
Other income (expense):
               
Interest expense, net
   
(50.9
)
   
(33.1
)
Equity earnings
   
1.7
     
4.9
 
Other
   
(12.8
)
   
-
 
Income before income taxes
   
77.6
     
132.4
 
Income tax benefit (expense):
               
Current
   
(0.5
)
   
(0.7
)
Deferred
   
(0.6
)
   
(0.4
)
     
(1.1
)
   
(1.1
)
Net income
   
76.5
     
131.3
 
Less: Net income attributable to noncontrolling interests
   
4.9
     
8.9
 
Net income attributable to Targa Resources Partners LP
 
$
71.6
   
$
122.4
 
                 
Net income attributable to general partner
 
$
42.5
   
$
33.8
 
Net income attributable to limited partners
   
29.1
     
88.6
 
Net income attributable to Targa Resources Partners LP
 
$
71.6
   
$
122.4
 
                 
Net income per limited partner unit - basic
 
$
0.21
   
$
0.79
 
Net income per limited partner unit - diluted
 
$
0.21
   
$
0.78
 
Weighted average limited partner units outstanding - basic
   
137.1
     
112.4
 
Weighted average limited partner units outstanding - diluted
   
137.5
     
113.0
 

See notes to consolidated financial statements.
 
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

 
Three Months Ended March 31,
 
 
2015
   
2014
 
 
(Unaudited)
 
 
(In millions)
 
   
Net income
 
$
76.5
   
$
131.3
 
Other comprehensive income (loss):
               
Commodity hedging derivative contracts:
               
Change in fair value
   
25.2
     
(11.9
)
Settlements reclassified to revenues
   
(8.1
)
   
6.3
 
Interest rate swaps:
               
Settlements reclassified to interest expense, net
   
-
     
1.3
 
Other comprehensive income (loss):
   
17.1
     
(4.3
)
Comprehensive income
   
93.6
     
127.0
 
Less: Comprehensive income attributable to noncontrolling interests
   
4.9
     
8.9
 
Comprehensive income attributable to Targa Resources Partners LP
 
$
88.7
   
$
118.1
 

See notes to consolidated financial statements.
 
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY
 
   
Limited
Partner
   
 
General
Partner
   
Special
General Partner
Interest
   
Receivables
From Unit
Issuances
   
Accumulated
Other
Comprehensive
Income (Loss)
   
 
Treasury
Units
   
Non-
controlling
Interests
   
Total
 
                                 
   
Common
   
Amount
   
Units
   
Amount
               
Units
   
Amount
         
   
(Unaudited)
 
   
(In millions, except units in thousands)
 
Balance December 31, 2014
   
118,586
   
$
2,384.1
     
2,420
   
$
78.6
   
$
-
   
$
(1.0
)
 
$
60.3
     
67
   
$
(4.8
)
 
$
171.2
   
$
2,688.4
 
Compensation on equity grants
   
-
     
3.8
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
3.8
 
Issuance of common units under compensation program
   
26
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
 
Units tendered for tax withholding obligations
   
(13
)
   
-
     
-
     
-
     
-
     
-
     
-
     
13
     
(0.6
)
   
-
     
(0.6
)
Equity offerings
   
1,271
     
53.0
     
-
     
-
     
-
     
(24.8
)
   
-
     
-
     
-
     
-
     
28.2
 
Issuance of units for acquisition
   
58,614
     
2,582.4
                     
-
     
-
     
-
     
-
     
-
     
303.9
     
2,886.3
 
Contributions from Targa Resources Corp.
   
-
     
-
     
1,222
     
53.4
     
-
     
0.2
     
-
     
-
     
-
     
-
     
53.6
 
Distributions to noncontrolling interests
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
(2.7
)
   
(2.7
)
Contributions from noncontrolling interests
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
3.4
     
3.4
 
Other comprehensive income (loss)
   
-
     
-
     
-
     
-
     
-
     
-
     
17.1
     
-
     
-
     
-
     
17.1
 
Net income
   
-
     
29.1
     
-
     
42.5
     
-
     
-
     
-
     
-
     
-
     
4.9
     
76.5
 
Distributions
   
-
     
(96.3
)
   
-
     
(41.1
)
   
-
     
-
     
-
     
-
     
-
     
-
     
(137.4
)
Targa contribution  - Special General Partner Interest
   
-
     
-
     
-
     
-
     
1,612.4
     
-
     
-
     
-
     
-
     
-
     
1,612.4
 
Allocation of special general partner interest
   
-
     
4.0
     
-
     
0.1
     
(4.1
)
   
-
     
-
     
-
     
-
     
-
     
-
 
Balance March 31, 2015
   
178,484
   
$
4,960.1
     
3,642
   
$
133.5
     
1,608.3
   
$
(25.6
)
 
$
77.4
     
80
   
$
(5.4
)  
$
480.7
   
$
7,229.0
 
                                                                                         
Balance December 31, 2013
   
111,263
   
$
2,001.9
     
2,271
   
$
62.0
   
$
-
   
$
-
   
$
(6.1
)
   
-
   
$
-
   
$
160.6
   
$
2,218.4
 
Compensation on equity grants
   
9
     
2.6
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
2.6
 
Accrual of distribution equivalent rights
   
-
     
(0.6
)
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
(0.6
)
Equity offerings
   
2,222
     
115.3
     
45
     
2.4
     
-
     
(7.1
)
   
-
     
-
     
-
     
-
     
110.6
 
Distributions to noncontrolling interests
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
(7.4
)
   
(7.4
)
Other comprehensive income (loss)
   
-
     
-
     
-
     
-
     
-
     
-
     
(4.3
)
   
-
     
-
     
-
     
(4.3
)
Net income
   
-
     
88.6
     
-
     
33.8
     
-
     
-
     
-
     
-
     
-
     
8.9
     
131.3
 
Distributions
   
-
     
(84.0
)
   
-
     
(31.8
)
   
-
     
-
     
-
     
-
     
-
     
-
     
(115.8
)
Balance March 31, 2014
   
113,494
   
$
2,123.8
     
2,316
   
$
66.4
   
$
-
   
$
(7.1
)
 
$
(10.4
)
   
-
   
$
-
   
$
162.1
   
$
2,334.8
 
 
See notes to consolidated financial statements.
 
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS

   
Three Months Ended March 31,
 
   
2015
   
2014
 
         
   
(Unaudited)
 
   
(In millions)
 
Cash flows from operating activities
       
Net income
 
$
76.5
   
$
131.3
 
Adjustments to reconcile net income to net cash provided by operating activities:
               
Amortization in interest expense
   
3.0
     
3.4
 
Compensation on equity grants
   
3.8
     
2.6
 
Depreciation and amortization expense
   
119.6
     
79.5
 
Accretion of asset retirement obligations
   
1.3
     
1.2
 
Deferred income tax expense (benefit)
   
0.6
     
0.4
 
Equity earnings of unconsolidated affiliates
   
(1.7
)
   
(4.9
)
Distributions received from unconsolidated affiliates
   
2.1
     
4.9
 
Risk management activities
   
6.6
     
(0.3
)
(Gain) loss on sale or disposition of assets
   
0.6
     
(0.8
)
(Gain) loss on debt redemptions and amendments
(0.1
)
-
Changes in operating assets and liabilities:
               
Receivables and other assets
   
82.2
     
50.6
 
Inventory
   
102.5
     
60.6
 
Accounts payable and other liabilities
   
(84.5
)
   
(12.1
)
Net cash provided by operating activities
   
312.5
     
316.4
 
Cash flows from investing activities
               
Outlays for property, plant and equipment
   
(187.6
)
   
(197.7
)
Business acquisition, net of cash acquired
   
(852.3
)
   
-
 
Return of capital from unconsolidated affiliate
   
0.6
     
2.2
 
Other, net
   
(0.6
)
   
1.8
 
Net cash used in investing activities
   
(1,039.9
)
   
(193.7
)
Cash flows from financing activities
               
Proceeds from borrowings under credit facility
   
975.0
     
460.0
 
Repayments of credit facility
   
(135.0
)
   
(500.0
)
Proceeds from issuance of senior notes
   
1,100.0
     
-
 
Proceeds from accounts receivable securitization facility
   
253.4
     
29.5
 
Repayments of accounts receivable securitization facility
   
(238.3
)
   
(75.7
)
Redemption of APL senior notes
   
(1,168.8
)
   
-
 
Costs paid in connection with debt and equity financing arrangements
   
(12.2
)
   
(1.2
)
Proceeds from equity offerings
   
28.2
     
109.4
 
Repurchase of common units under compensation plans
   
(0.6
)
   
-
 
Distributions paid to unit-holders
   
(137.4
)
   
(115.8
)
Contributions received from General Partner
   
53.6
     
2.4
 
Contributions received from noncontrolling interests
   
3.4
     
-
 
Distributions paid to noncontrolling interests
   
(2.7
)
   
(7.4
)
Net cash provided by (used in) financing activities
   
718.6
     
(98.8
)
Net change in cash and cash equivalents
   
(8.8
)
   
23.9
 
Cash and cash equivalents, beginning of period
   
72.3
     
57.5
 
Cash and cash equivalents, end of period
 
$
63.5
   
$
81.4
 

See notes to consolidated financial statements.
 
TARGA RESOURCES PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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

Note 1 — Organization and Operations

Our Organization

Targa Resources Partners LP is a publicly traded Delaware limited partnership formed in October 2006 by Targa. Our common units, which represent limited partner interests in us, are listed on the New York Stock Exchange under the symbol “NGLS.” In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries.

Targa Resources GP LLC 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. As of March 31, 2015, Targa owned an 11.0% interest in us in the form of 3,642,543 general partner units and 16,309,594 common units. In addition, Targa Resources GP LLC also owns incentive distribution rights (“IDRs”), which entitle it to receive increasing cash distributions up to 48% of distributable cash for a quarter, exclusive of amounts reallocated to common unit-holders under the IDR Giveback Amendment (see Note 11).
 
In connection with the Atlas mergers, our partnership agreement was amended to provide for the issuance of a special general partner interest (“the Special GP Interest”) representing a capital account credit equal to the tax basis of the APL GP Interests acquired in the ATLS merger. The Special GP Interest is not entitled to current distributions or allocations of net income or loss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL GP.
 
Allocation of costs

The employees supporting our operations are employed by Targa. Our 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 centralized general and administrative services.

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; gathering, storing and terminaling crude oil; and storing, terminaling and selling refined petroleum products. See Note 18 for certain financial information for our business segments.

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 February 27, 2015 Atlas mergers involved two separate legal transactions involving different groups of unitholders. For GAAP reporting purposes these two mergers are viewed as a single integrated transaction.  As such, the financial effects of the Targa consideration related to the ATLS merger have been reflected in these financial statements. As described in Note 1, our Partnership Agreement was amended to provide for the issuance of a special general partner interest in us representing a capital account credit equal to the tax basis of the APL GP Interests acquired in the ATLS merger totaling $1.6 billion. The Special GP Interest is not entitled to current distributions or allocations of net income or loss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL GP. Pending finalization of our fair value acquisition accounting, we have attributed goodwill and intangible assets to this special capital account and have reflected the related financial effects in our Owners’ Equity.
 
The unaudited consolidated financial statements for the three months ended March 31, 2015 and 2014 include all adjustments that we believe are necessary for a fair presentation 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, 2015 are not necessarily indicative of the results that may be expected for the full year.

Note 3 — Significant Accounting Policies

Accounting Policy Updates/Revisions

The accounting policies that we follow are set forth in Note 3 of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K. We have updated our policies during the three months ended March 31, 2015 to include our accounting policy for goodwill related to the Atlas mergers.

Goodwill results when the cost of an acquisition exceeds the fair value of the net identifiable assets of the acquired business. Goodwill is not amortized, but is assessed annually to determine whether its carrying value has been impaired.

Impairment testing for goodwill is performed at the reporting unit level. A reporting unit is an operating segment or one level below an operating segment (also known as a component). A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available, and segment management regularly reviews the operating results of that component.

We evaluate goodwill for impairment at least annually, as of November 30th for all affected reporting units. We also evaluate goodwill for impairment whenever events or changes in circumstances indicate it is more likely than not the fair value of a reporting unit is less than its carrying amount. We may first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount (including assigned goodwill) as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. If a two-step process goodwill impairment test is required, the first step involves comparing the fair value of the reporting unit to which goodwill has been allocated with its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as a reduction of goodwill on our Consolidated Balance Sheets and a goodwill impairment loss on our Consolidated Statements of Operations.

Recent Accounting Pronouncements

In February 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The amendments are intended to simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities and modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities. The amendments are effective for us in 2016, with early adoption permitted. We are currently evaluating the effect of the amendments on our consolidated financial statements and related disclosures.
 
In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. The amendments are effective for us in 2016, with early adoption permitted. We anticipate adopting the amendments on January 1, 2016. Unamortized debt issuance costs of $46.4 million were included in Other long-term assets on the Consolidated Balance Sheets as of March 31, 2015.
 
Note 4 –Business Acquisitions

2015 Acquisition

Atlas Mergers
 
On February 27, 2015, (i) Targa completed the previously announced transactions contemplated by the Agreement and Plan of Merger, dated as of October 13, 2014 (the “ATLS Merger Agreement”), by and among Targa, Targa GP Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of Targa (“GP Merger Sub”), ATLS and Atlas Energy GP, LLC, a Delaware limited liability company and the general partner of ATLS (“ATLS GP”), and (ii) Targa and the Partnership completed the previously announced transactions contemplated by the Agreement and Plan of Merger (the “APL Merger Agreement” and, together with the ATLS Merger Agreement, the “Atlas Merger Agreements”) by and among Targa, the Partnership, our general partner, Trident MLP Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of the Partnership (“MLP Merger Sub”), ATLS, APL and Atlas Pipeline Partners GP, LLC, a Delaware limited liability company and the general partner of APL (“APL GP”). Pursuant to the terms and conditions set forth in the ATLS Merger Agreement, GP Merger Sub merged (the “ATLS merger”) with and into ATLS, with ATLS continuing as the surviving entity and as a subsidiary of Targa. Pursuant to the terms and conditions set forth in the APL Merger Agreement, MLP Merger Sub merged (the “APL merger” and, together with the ATLS merger, the “Atlas mergers”) with and into APL, with APL continuing as the surviving entity and as a subsidiary of the Partnership.
 
In connection with the Atlas mergers, APL changed its name to “Targa Pipeline Partners LP,” which we refer to as TPL, and ATLS changed its name to “Targa Energy LP.”

In addition, prior to the completion of the Atlas mergers, ATLS, pursuant to a Separation and Distribution Agreement entered into by and among ATLS, ATLS GP and Atlas Energy Group, LLC, a Delaware limited liability company (“AEG”), on February 27, 2015, (i) transferred its assets and liabilities other than those related to its “Atlas Pipeline Partners” segment, to AEG and (ii) effected a pro rata distribution to the ATLS unitholders of AEG common units representing a 100% interest in AEG (collectively, the “Spin-Off” and, together with the Atlas mergers, the “Atlas Transactions”).

 
We acquired all of the outstanding units of APL for a total purchase price of approximately $5.3 billion (including $1.8 billion of acquired debt and all other assumed liabilities). Of the $1.8 billion of debt acquired and other liabilities assumed, approximately $1.2 billion of the acquired debt was tendered and settled upon the closing of the Atlas mergers via our January 2015 cash tender offers. These tender offers were in connection with, and conditioned upon, the consummation of the merger with APL. The merger with APL, however, was not conditioned on the consummation of the tender offers. On that same date, Targa acquired ATLS for a total purchase price of approximately $1.6 billion (including all assumed liabilities).
 
On February 27, 2015, our Partnership Agreement was amended to provide for the issuance of a special general partner interest in us representing a capital account credit equal to the tax basis of the APL GP Interests acquired in the ATLS merger totaling $1.6 billion, which, through a series of transactions, was contributed by Targa to us immediately following the effective time of the ATLS merger and prior to the effective time of the APL merger. The Special GP Interest is not entitled to current distributions or allocations of net income or loss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL GP. Pending finalization of our fair value acquisition accounting, we have attributed goodwill and intangible assets to this special capital account and have reflected the related financial effects in Owners’ Equity.

Pursuant to the APL Merger Agreement, our general partner entered into an amendment to our partnership agreement in order to reduce aggregate distributions to TRC, as the holder of the Partnership’s IDRs by (a) $9,375,000 per quarter during the first four quarters following the APL merger, (b) $6,250,000 per quarter for the next four quarters, (c) $2,500,000 per quarter for the next four quarters and (d) $1,250,000 per quarter for the next four quarters, with the amount of such reductions to be distributed pro rata to the holders of our outstanding common units.
 
TPL is a provider of natural gas gathering, processing and treating services primarily in the Anadarko, Arkoma and Permian Basins located in the southwestern and mid-continent regions of the United States and in the Eagle Ford Shale play in south Texas. The Atlas mergers add TPL’s Woodford/SCOOP, Mississippi Lime, Eagle Ford and additional Permian assets to the Partnership’s existing operations and creates a combined position across the Permian Basin that enhances service capabilities in one of the most active producing basins in North America, with a combined 1,439 MMcf/d of processing capacity and 10,500 miles of pipelines. The results of TPL will be reported in our Field Gathering and Processing segment.
 
The APL merger was a unit-for-unit transaction with an exchange ratio of 0.5846 of our common units (the “APL Unit Consideration”) and $1.26 in cash for each APL common unit (the “APL Cash Consideration” and with the APL Unit Considerations, the “APL Merger Consideration”), a $128.0 million total cash payment, of which $0.6 million was expensed at the acquisition date as the cash payment representing accelerated vesting of a portion of retained employees' APL phantom awards. We issued 58,614,157 of our common units and awarded 629,231 replacement phantom unit awards with a combined value of approximately $2.6 billion as consideration for the APL merger (based on the $43.82 closing market price of a common unit on the NYSE on February 27, 2015). The cash component of the APL Merger also included $701.4 million for the mandatory repayment and extinguishment at closing of the APL Senior Secured Revolving Credit Facility that was to mature in May 2017 (the “APL Revolver”), $28.8 million related to change of control payments and $6.4 million of cash paid in lieu of unit issuances in connection with settlement of APL equity awards for AEG employees. In March 2015, Targa contributed $52.4 million to us to maintain its 2% general partner interest.
 
In addition, pursuant to the APL Merger Agreement, APL exercised its right under the certificate of designations of the APL 8.25% Class E cumulative redeemable perpetual preferred units (“Class E Preferred Units”) to redeem the APL Class E Preferred Units immediately prior to the APL Effective Time.
 
The ATLS merger was a stock-for-unit transaction with an exchange ratio of 0.1809 of Targa common stock, par value $0.001 per share (the “ATLS Stock Consideration”), and $9.12 in cash for each ATLS common unit (the “ATLS Cash Consideration” and with the ATLS Stock Consideration, the “ATLS Merger Consideration”), (a $514.7 million total cash payment). Targa issued 10,126,532 of its common shares and awarded 81,740 replacement restricted stock units with a combined value of approximately $1.0 billion for the ATLS merger (based on the $99.58 closing market price of a TRC common share on the NYSE on February 27, 2015). The cash component of the ATLS merger also included approximately $149.2 million for change of control payments and cash settlements of equity awards, $88.0 million for repayment of a portion of ATLS outstanding indebtedness and $11.0 million for reimbursement of certain transaction expenses. Approximately $4.5 million of the one-time cash payments and cash settlements of equity awards, which represent accelerated vesting of a portion of retained employees’ ATLS phantom units, were expensed at the acquisition date.
 
ATLS owned, directly and indirectly, 5,754,253 APL common units immediately prior to closing. Targa’s acquisition of ATLS resulted in Targa acquiring these common units (converted to 3,363,935 of our common units) valued at approximately $147.4 million (based on the $43.82 closing market price of our common units on the NYSE on February 27, 2015) and the right to receive the units’ one-time cash payment of approximately $7.3 million, which reduced the consolidated purchase price by approximately $154.7 million.
 
While these were two separate legal transactions involving different groups of unitholders, for GAAP reporting purposes these two mergers are viewed as a single integrated transaction.  As such, the financial effects of the Targa consideration related to the ATLS merger have been reflected in these financial statements. The preliminary fair value determination at the Targa level identified $984.2 million of intangible value and $0.4 million, net, of current liabilities, as of the acquisition date of February 27, 2015. The excess of the purchase price over the estimated fair value of net assets acquired was approximately $628.5 million, which was recorded as goodwill.

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

Pro forma Impact of Atlas Mergers on Consolidated Statements of Operations

The acquired business contributed revenues of $160.6 million and net income of $4.1 million to us for the period from February 27, 2015 to March 31, 2015, and is reported in our Field Gathering and Processing segment. In 2015, we incurred $13.7 million of acquisition-related costs. These expenses are included in other expense in our Consolidated Statement of Operations for the three months ended March 31, 2015.
 
The following summarized unaudited pro forma consolidated statement of operations information for the three months ended March 31, 2015 and March 31, 2014 assumes that our acquisition of APL and Targa’s acquisition of ATLS had occurred as of January 1, 2014. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma financial results may not be indicative of the results that would have occurred if we had completed the APL merger as of January 1, 2014, or that the results that will be attained in the future. Amounts presented below are in millions, except for the per unit amounts:
 
   
March 31, 2015
   
March 31, 2014
 
   
Pro forma
   
Pro forma
 
         
Revenues
 
$
1,994.0
   
$
2,944.4
 
Net income
   
71.7
     
129.2
 

The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making adjustments to:
 
· Reflect the change in amortization expense resulting from the difference between the historical balances of APL’s intangible assets, net, and our preliminary estimate of the fair value of intangible assets acquired.
· Reflect the change in interest expense resulting from our financing activities directly related to the Atlas mergers as compared with APL’s historical interest expense.
· Reflect the changes in stock-based compensation expense related to the fair value of the unvested portion of replacement Partnership LTIP awards, which were issued in connection with the acquisition to APL phantom unitholders who will continue to provide service as Targa employees.
· Remove the results of operations attributable to APL businesses sold during the periods: (1) the May 2014 sale of APL’s 20% interest in West Texas LPG Pipeline Limited Partnership and (2) the February 2015 transfer of 100% of APL’s interest in gas gathering assets located in the Appalachian Basin of Tennessee to Atlas Resource Partners, L.P.
·
Exclude $13.7 million of acquisition-related costs incurred in 2015 from pro forma net income for the three months ended March 31, 2015. Pro forma net income for the three months ended March 31, 2014 was adjusted to include these charges.
 
The following table summarizes the consideration transferred to acquire ATLS and APL, which are viewed together as a single integrated transaction for GAAP reporting purposes:
 
Fair Value of Consideration Transferred by Targa for ATLS:
 
Cash, net of cash acquired (1)
 
$
745.7
 
Common shares of TRC
   
1,008.5
 
Replacement restricted stock units awarded (3)
   
5.2
 
Less: value of  APL common units owned by ATLS
   
(147.4
)
Total
 
$
1,612.0
 
         
Fair Value of Consideration Transferred for APL:
 
Cash, net of cash acquired (2)
 
$
852.3
 
Common units of TRP
   
2,568.5
 
Replacement phantom units awarded (3)
   
15.0
 
Total
 
$
3,435.8
 
         
Total fair value of consideration transferred
 
$
5,047.8
 
___________
(1) Targa acquired $5.5 million of cash. Targa also received $7.3 million in April 2015 as part of the Atlas mergers, representing the one-time cash payment from us for the APL common units owned by ATLS.
(2) We acquired $11.7 million of cash.
(3)
The fair value of consideration transferred in the form of replacement restricted stock unit awards and replacement phantom unit awards represent the allocation of the fair value of the awards to the pre-combination service period. The fair value of the awards associated with the post-combination service period will be recognized over the remaining service period of the award.
 
As of February 27, 2015, our preliminary fair value determination related to the Atlas mergers was as follows. The excess of the purchase price over the estimated fair value of net assets acquired was approximately $628.5 million, which was recorded as goodwill. This determination is based on our preliminary valuation and is subject to revisions pending the completion of valuation and other adjustments.

Preliminary fair value determination:
 
February 27, 2015
 
Trade and other current receivables, net
 
$
183.9
 
Other current assets
   
26.5
 
Assets from risk management activities
   
102.1
 
Property, plant and equipment
   
4,944.0
 
Investments in unconsolidated affiliates
   
273.7
 
Intangible assets
   
1,035.0
 
Other long-term assets
   
6.6
 
Current liabilities, less current portion of long-term debt
   
(233.5
)
Long-term debt
   
(1,573.8
)
Deferred income tax liabilities, net
   
(30.2
)
Other long-term liabilities
   
(10.7
)
Noncontrolling interest in subsidiaries
   
(303.9
)
Total identifiable net assets
 
$
4,419.7
 
Current liabilities retained by Targa
 
$
(0.4
)
Goodwill
 
$
628.5
 

Our valuation of the acquired assets and liabilities is ongoing and may result in future measurement period adjustments to these preliminary fair values. The fair values of property, plant and equipment, investments in unconsolidated affiliates, intangible assets representing the GP interest, IDRs, customer contracts and customer relationships, deferred income taxes related to APL Arkoma, Inc., a taxable subsidiary acquired, and noncontrolling interest, which is calculated as a proportionate share of the fair value of the acquired joint ventures’ net assets, are provisional pending completion of final valuations. As a result, goodwill is also provisional, as it has been recorded as the excess of the purchase price over the estimated fair value of net assets acquired.
 
The preliminary 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.
 
The preliminary determination of goodwill of $628.5 million is attributable to the workforce of the acquired business and the significant synergies expected to arise after Targa’s acquisition of ATLS and our acquisition of APL. The goodwill is expected to be amortizable for tax purposes. The allocation of the goodwill to our reporting units will be completed in conjunction with our finalization of the fair value determination.
 
The fair value of assets acquired includes trade receivables of $180.9 million. The gross amount due under contracts is $180.9 million, all of which is expected to be collectible. The fair value of assets acquired includes receivables related to a contractual settlement with a counterparty of $3.0 million reported in current receivables and $4.5 million reported in other long-term assets both of which are expected to be collectible.
 
See Note 10, for additional disclosures regarding related financing activities associated with the Atlas mergers.
 
Contingent Consideration

A liability arising from the contingent consideration for APL’s previous acquisition of a gas gathering system and related assets has been recognized at fair value. APL agreed to pay up to an additional $6.0 million if certain volumes are achieved on the acquired gathering system within a specified time period. As of February 27, 2015, the fair value of the remaining contingent payment resulted in a $6.0 million long term liability, which is recorded within other long term liabilities on our Consolidated Balance Sheets. The range of the undiscounted amount that we could pay related to the remaining contingent payment is between $0.0 and $6.0 million. The fair value of this contingent liability is preliminary as of March 31, 2015 as we are in the process of assessing the probabilities of production forecast scenarios and the resulting impact on this contingent valuation.

Replacement Phantom Units

In connection with the Atlas mergers, we awarded replacement phantom units in accordance with and as required by the Atlas Merger Agreements to those APL employees who became Targa employees after the acquisition. The vesting dates and terms remained unchanged from the existing APL awards, and will vest over the remaining terms of the awards, which are either 25% per year over the original four year term or 33% per year over the original three year term.

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

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

Note 5 — Inventories
 
   
March 31, 2015
   
December 31, 2014
 
Commodities
 
$
66.9
   
$
157.4
 
Materials and supplies
   
11.3
     
11.5
 
   
$
78.2
   
$
168.9
 
 

Note 6 — Property, Plant and Equipment and Intangible Assets

   
March 31, 2015
   
December 31, 2014
   
Estimated useful life
(In years)
 
Gathering systems
 
$
6,113.8
   
$
2,588.6
   
5 to 40
 
Processing and fractionation facilities
   
2,924.6
     
1,884.1
   
5 to 40
 
Terminaling and storage facilities
   
1,043.0
     
1,038.9
   
5 to 25
 
Transportation assets
   
432.9
     
359.0
   
10 to 25
 
Other property, plant and equipment
   
219.9
     
149.1
   
3 to 40
 
Land
   
101.4
     
95.6
     -  
Construction in progress
   
782.2
     
399.0
     -  
Property, plant and equipment
   
11,617.8
     
6,514.3
         
Accumulated depreciation
   
(1,784.9
)
   
(1,689.7
)
       
Property, plant and equipment, net
 
$
9,832.9
   
$
4,824.6
         
                         
Intangible assets
 
$
1,716.6
   
$
681.8
     20  
Accumulated amortization
   
(114.2
)
   
(89.9
)
       
Intangible assets, net
 
$
1,602.4
   
$
591.9
         

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

The fair values of intangible assets acquired in the Atlas mergers have been recorded at a provisional value of $1,035.0 million pending completion of final valuations. For the purpose of our preparing the accompanying financial statements (which include one month of amortization of these intangible assets) we have amortized these intangible assets over a 20 year life using a straight-line method. The amortization method and lives for the Atlas mergers intangible assets will be reviewed and possibly revised as we finalize the valuations over the upcoming months.

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. The estimated annual amortization expense for intangible assets, including the provisional Atlas valuation and straight-line treatment is approximately $123.2 million, $140.1 million, $133.3 million, $119.5 million and $108.6 million for each of the years 2015 through 2019.
 
Note 7 — Investments in Unconsolidated Affiliates

At December 31, 2014, our unconsolidated investment consisted of a 38.8% ownership interest in Gulf Coast Fractionators LP (“GCF”). As of March 31, 2015, we continue to have a 38.8% ownership interest in GCF.

On February 27, 2015, as part of the Atlas mergers, we acquired equity interests in three non-operated joint ventures in South Texas; (1) a 75% interest in T2 LaSalle, (2) a 50% interest in T2 Eagle Ford and (3) a 50% interest in T2 EF Co-Gen (together the “T2 Joint Ventures”). The T2 Joint Ventures were formed to provide services for the benefit of the joint interest owners. The T2 Joint Ventures have capacity lease agreements with the joint interest owners, which cover the costs of operations of the T2 Joint Ventures. The terms of these joint venture agreements do not afford us the degree of control required for consolidating them in our financial statements, but do afford us the significant influence required to employ the equity method of accounting.
 
The following table shows the activity related to our investments in unconsolidated affiliates:

   
Three Months Ended March 31, 2015
 
Beginning of period
 
$
50.2
 
Preliminary fair value of T2 Joint Ventures acquired (1)
   
273.7
 
Equity earnings
   
1.7
 
Cash distributions (2)
   
(2.7
)
End of period
 
$
322.9
 
___________
(1) Includes equity earnings of acquired investments since the date of acquisition of February 27, 2015.
(2) Includes $0.6 million distributions received in excess of our share of cumulative earnings for the three months ended March 31, 2015. Such excess distributions are considered a return of capital and are disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows.

The allocated cost basis of the T2 Joint Ventures investment is based on preliminary fair values at the date of acquisition with a basis difference of approximately $99.1 million. This basis difference is being amortized over the preliminary estimated useful lives of the underlying assets of 20 years on a straight-line basis and is included as a component of equity earnings. See Note 4 for further information regarding the preliminary fair value determinations related to the Atlas mergers.

Note 8 Accounts Payable and Accrued Liabilities

   
March 31, 2015
   
December 31, 2014
 
Commodities
 
$
445.8
   
$
416.7
 
Other goods and services
   
169.8
     
108.9
 
Interest
   
57.0
     
37.3
 
Compensation and benefits
   
3.2
     
1.3
 
Income and other taxes
   
20.0
     
13.6
 
Other
   
15.0
     
14.9
 
   
$
710.8
   
$
592.7
 

Note 9 — Asset Retirement Obligations

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

   
Three Months Ended March 31, 2015
 
Beginning of period
 
$
56.8
 
Preliminary fair value of ARO acquired with the APL merger
   
4.1
 
Change in cash flow estimate
   
3.7
 
Accretion expense
   
1.3
 
End of period
 
$
65.9
 
 
Note 10 — Debt Obligations

   
March 31, 2015
   
December 31, 2014
 
         
Current:
       
Accounts receivable securitization facility, due December 2015
 
$
197.9
   
$
182.8
 
                 
Long-term:
               
Senior secured revolving credit facility, variable rate, due October 2017 (1)
   
840.0
     
-
 
Senior unsecured notes, 5% fixed rate, due January 2018
   
1,100.0
     
-
 
Senior unsecured notes, 6% fixed rate, due February 2021
   
483.6
     
483.6
 
Unamortized discount
   
(24.5
)
   
(25.2
)
Senior unsecured notes, 6% fixed rate, due August 2022
   
300.0
     
300.0
 
Senior unsecured notes, 5¼% fixed rate, due May 2023
   
600.0
     
600.0
 
Senior unsecured notes, 4¼% fixed rate, due November 2023
   
625.0
     
625.0
 
Senior unsecured notes, 4% fixed rate, due November 2019
   
800.0
     
800.0
 
Senior unsecured notes, 6% fixed rate, due October 2020 (2)
   
355.1
     
-
 
Unamortized premium
   
6.0
     
-
 
Senior unsecured notes, 4¾% fixed rate, due November 2021 (2)
   
6.5
     
-
 
Senior unsecured notes, 5⅞% fixed rate, due August 2023 (2)
   
48.1
     
-
 
Unamortized premium
   
0.6
     
-
 
Total long-term debt
   
5,140.4
     
2,783.4
 
                 
Total debt
 
$
5,338.3
   
$
2,966.2
 
                 
Letters of credit outstanding
 
$
25.0
   
$
44.1
 
________
(1) As of March 31, 2015, availability under our $1.6 billion senior secured revolving credit facility was $735.0 million.
(2) Senior unsecured notes issued by APL entities and acquired in the Atlas mergers.

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, 2015:

 
Range of Interest Rates Incurred
 
Weighted Average Interest Rate Incurred
Senior secured revolving credit facility
1.9%
 
1.9%
Accounts receivable securitization facility
0.9%
 
0.9%

Compliance with Debt Covenants

As of March 31, 2015, we were in compliance with the covenants contained in our various debt agreements.

Merger Financing Activities

Revolving Credit Agreement

In February 2015, we entered into the First Amendment, Waiver and Incremental Commitment Agreement (the “First Amendment”) that amended our Second Amended and Restated Credit Agreement (the “Original Agreement”). The First Amendment increased available commitments to $1.6 billion from $1.2 billion while retaining our ability to request up to an additional $300.0 million in commitment increases. In addition, the First Amendment amends certain provisions of the Original Agreement and designates each of APL and its subsidiaries as an “Unrestricted Subsidiary.” We used proceeds from borrowings under the credit facility to fund cash components of the APL merger, including $701.4 million for the repayments of the APL Revolver and $28.8 million related to change of control payments.
 
Senior Unsecured Notes

In January 2015, we privately placed $1,100.0 million in aggregate principal amount of 5% Senior Notes due 2018 (the “5% Notes”). The 5% Notes resulted in approximately $1,089.8 million of net proceeds, which were used with borrowings under our revolver to fund the APL Note Tender Offers (as defined below). The 5% Notes are unsecured senior obligations that have the same terms and covenants as our other senior notes.

APL Senior Notes Tender Offers

In January 2015, we commenced cash tender offers for any and all of the outstanding fixed rate senior notes acquired in the APL merger (“APL Notes”), referred to as the APL Note Tender Offers, which totaled $1,550.0 million.

The results of the APL Note Tender Offers were:

Senior Notes
 
Outstanding Note Balance
   
Amount Tendered
   
Premium Paid
   
Accrued Interest Paid
   
Total Tender Offer payments
   
% Tendered
   
Note Balance after Tender Offers
 
   
($ amounts in millions)
         
6⅝% due 2020
 
$
500.0
   
$
140.1
   
$
2.1
   
$
3.7
   
$
145.9
     
28.02
%
 
$
359.9
 
4¾% due 2021
   
400.0
     
393.5
     
5.9
     
5.3
     
404.7
     
98.38
%
   
6.5
 
5⅞% due 2023
   
650.0
     
601.9
     
8.7
     
2.6
     
613.2
     
92.60
%
   
48.1
 
Total
 
$
1,550.0
   
$
1,135.5
   
$
16.7
   
$
11.6
   
$
1,163.8
           
$
414.5
 

In connection with the APL Notes Tender Offers, on February 27, 2015, (i) the First Supplemental Indenture (the “2021 APL Notes Supplemental Indenture”) to the Indenture, dated as of May 10, 2013, by and among the APL Issuers, the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee, governing the 2021 APL Notes, became operative, and (ii) the Third Supplemental Indenture (the “2023 APL Notes Supplemental Indenture” and, together with the 2021 APL Notes Supplemental Indenture, the “February APL Supplemental Indentures”) to the Indenture, dated as of February 11, 2013, by and among the APL Issuers, the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee, governing the 2023 APL Notes, became operative. The February APL Supplemental Indentures eliminate substantially all of the restrictive covenants and certain events of default applicable to the 2021 APL Notes and the 2023 APL Notes that were not accepted for payment. The indenture governing the 2020 APL Notes (the “2020 APL Notes Indenture”) remained unchanged at such time.

Not having achieved the minimum tender condition on the 2020 APL Notes, the change of control terms of the 2020 APL Notes Indenture required the APL Issuers to offer holders $1,010 for each $1,000 principal amount of outstanding notes plus accrued and unpaid interest from the most recent interest payment date. As permitted by the 2020 APL Notes Indenture, in lieu of the APL issuers, we made a change of control offer for any and all of the 2020 APL Notes and in advance of, and conditioned upon, the consummation of the APL merger. Holders representing $4.8 million of the outstanding 2020 APL Notes tendered their notes requiring a payment of $5.0 million, which included the change of control premium and accrued interest.

Payments made under the APL Notes Tender Offers and Change of Control Offer totaling $1,168.8 million are presented as financing activities in the Statement of Cash Flows.
 
Subsequent event. On April 13, 2015, we and Targa Resources Partners Finance Corporation (collectively, the “Partnership Issuers” commenced an offer to exchange (the “Exchange Offer”) any and all of the outstanding 2020 APL Notes, which had an aggregate principal amount outstanding of $355.1 million, for an equal amount of new unsecured 6 5/8% Senior Notes due 2020 issued by the Partnership Issuers (the “6 5/8% Notes”). On April 27, 2015, the Partnership Issuers had received tenders and consents from holders of approximately $341.9 million in aggregate principal amount of the 2020 APL Notes, representing approximately 96.3% of the total outstanding $355.1 million in aggregate principal amount of the 2020 APL Notes. As a result, the minimum tender condition to the Exchange Offer and related consent solicitation has been satisfied, and the APL Issuers executed a supplemental indenture (the “APL Supplemental Indenture”) effecting the proposed amendments with respect to the 2020 APL Notes, which satisfied the second condition.
 
The APL Supplemental Indenture eliminates substantially all of the restrictive covenants and certain events of default applicable to the 2020 APL Notes. Consummation of the Exchange Offer, however, remains subject to certain other customary conditions. Settlement of the Exchange Offer will occur promptly after the Exchange Offer expires, which will be at 11:59 p.m., New York City time, on May 8, 2015, unless otherwise extended or terminated by the Partnership Issuers. The APL Supplemental Indenture will become operative upon settlement of the Exchange Offer.
 
Subsequent Event

In April 2015, we filed with the SEC a universal shelf registration statement that allows us to issue up to an aggregate of $1.0 billion of debt or equity securities (the "April 2015 Shelf"). The April 2015 Shelf expires in April 2018.
 
Note 11 — Partnership Units and Related Matters

Issuances of Common Units
 
As part of the APL mergers, we issued 58,614,157 common units to former APL unitholders as consideration for the APL mergers, of which 3,363,935 common units represented ATLS’s common unit ownership in APL and were issued to Targa.
 
In May 2014, we entered into an additional Equity Distribution Agreement under a shelf registration statement filed in July 2013 (the “May 2014 EDA”), pursuant to which we may sell through our sales agents, at our option, up to an aggregate of $400.0 million of our common units. During the three months ended March 31, 2015, we issued 1,271,876 common units under the May 2014 EDA, receiving total net proceeds of $53.0 million (net of commissions up to 1% of gross proceeds to our sales agent) of which $24.8 million was received in April. Targa contributed $1.1 million to us to maintain its 2% general partner interest, of which $0.8 million was received in April 2015.
 
Subsequent Event

During April 2015, we issued 2,318,950 common units under the May 2014 EDA, receiving net proceeds of $100.1 million. Targa contributed $2.1 million to us to maintain its 2% general partner interest. As of April 20, 2015, approximately $4.2 million of the aggregate offering amount remained available for sale pursuant to the May 2014 EDA.
 
Distributions

We must distribute all of our available cash, as defined in the Partnership Agreement, and as determined by the general partner, to unitholders of record within 45 days after the end of each quarter. The following table details the distributions declared and/or paid by us for the three months ended March 31, 2015.
 
     
Distributions
     
Three Months Ended
Date Paid or to be Paid
Limited Partners
 
General Partner
       
 
Distributions per Limited Partner Unit
 
Common
 
 
Incentive Distribution Rights
 
 
2%
Total
                       
     
(In millions, except per unit amounts)
 
                       
March 31, 2015
May 15, 2015
 
$
148.3
   
$
41.7
   
$
3.9
   
$
193.9
   
$
0.8200
 
December 31, 2014
February 13, 2015
 
$
96.3
   
$
38.4
   
$
2.7
   
$
137.4
   
$
0.8100
 
____________
(1) Pursuant to the IDR Giveback Amendment in conjunction with the Atlas mergers, IDR’s of $9.375 million were allocated to common unitholders in the first quarter of 2015. The IDR Giveback Amendment covers sixteen quarterly distribution declarations following the February 27, 2015 Atlas mergers and will result in reallocation of IDR payments to common unitholders at the following amounts - $9.375 million per quarter for 2015, $6.25 million per quarter for 2016, $2.5 million per quarter for 2017 and $1.25 million per quarter for 2018.

Note 12 — Earnings per Limited Partner Unit

The following table sets forth a reconciliation of net income and weighted average shares outstanding used in computing basic and diluted net income per limited partner unit:

   
Three Months Ended March 31,
 
   
2015
   
2014
 
Net income
 
$
76.5
   
$
131.3
 
Less: Net income attributable to noncontrolling interests
   
4.9
     
8.9
 
Net income attributable to Targa Resources Partners LP
 
$
71.6
   
$
122.4
 
                 
Net income attributable to general partner
 
$
42.5
   
$
33.8
 
Net income attributable to limited partners
   
29.1
     
88.6
 
Net income attributable to Targa Resources Partners LP
 
$
71.6
   
$
122.4
 
                 
Weighted average units outstanding - basic
   
137.1
     
112.4
 
                 
Net income available per limited partner unit - basic
 
$
0.21
   
$
0.79
 
                 
Weighted average units outstanding
   
137.1
     
112.4
 
Dilutive effect of unvested stock awards
   
0.4
     
0.6
 
Weighted average units outstanding - diluted
   
137.5
     
113.0
 
                 
Net income available per limited partner unit - diluted
 
$
0.21
   
$
0.78
 

Note 13 — Derivative Instruments and Hedging Activities

Commodity Hedges

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 Field Gathering and Processing segment and (ii) NGL and condensate equity volumes predominately in our Field Gathering and Processing segment and the LOU business unit in our Coastal 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 New York Mercantile Exchange (“NYMEX”) futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This necessarily exposes us to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes.
 
As part of the Atlas mergers, outstanding APL derivative contracts with a fair value of $102.1 million as of the acquisition date were novated to the Partnership, intended as cash flow hedges related to future TPL equity volumes. As the fair value of these APL derivative contracts settle, we will receive cash representing the future benefit of these contracts. For the quarter ended March 31, 2015, $7.8 million of the acquisition date fair value of the APL derivative contracts was received as a component of the derivative contract settlements.
                                                     
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 have to 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. Certain novated APL crude options with a fair value of $7.7 million as of the acquisition date did not fall within the “highly effective” correlation range required to qualify as a hedging instrument for accounting purposes and resulted in $0.5 million of mark-to-market gains included in our first quarter 2015 earnings. These crude oil options expire during 2015. Additionally our first quarter included $1.0 million of ineffectiveness gains related to otherwise qualifying APL derivatives, primarily natural gas swaps.

At March 31, 2015, the notional volumes of our commodity hedges were:

Commodity
 
Instrument
 
Unit
   
2015
 
2016
 
2017
Natural Gas
 
Swaps
 
MMBtu/d
   
 125,439
 
 68,205
 
 23,082
Natural Gas
 
Basis Swaps
 
MMBtu/d
   
 23,782
 
 -
 
 -
NGL
 
Swaps
 
Bbl/d
   
 5,928
 
 2,254
 
 658
NGL
 
Options
 
Bbl/d
   
 899
 
 790
 
 790
Condensate
 
Swaps
 
Bbl/d
   
 1,991
 
 1,082
 
 500
Condensate
 
Options
 
Bbl/d
   
 1,198
 
 380
 
 380

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 we record changes in fair value and cash settlements to revenues.

Our derivative contracts are subject to netting arrangements that allow net cash settlement of 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, 2015
   
Fair Value as of December 31, 2014
 
 
 
Balance Sheet
Location
 
Derivative
Assets
   
Derivative
Liabilities
   
Derivative
Assets
   
Derivative
Liabilities
 
Derivatives designated as hedging instruments
               
Commodity contracts
Current
 
$
117.8
   
$
0.4
   
$
44.4
   
$
-
 
 
Long-term
   
51.2
     
1.8
     
15.8
     
-
 
Total derivatives designated as hedging instruments
 
$
169.0
   
$
2.2
   
$
60.2
   
$
-
 
                                  
Derivatives not designated as hedging instruments
                               
Commodity contracts
Current
 
$
8.2
   
$
0.2
   
$
-
   
$
5.2
 
Total derivatives not designated as hedging instruments
 
$
8.2
   
$
0.2
   
$
-
   
$
5.2
 
                                  
Total current position
 
$
126.0
   
$
0.6
   
$
44.4
   
$
5.2
 
Total long-term position
   
51.2
     
1.8
     
15.8
     
-
 
Total derivatives
 
$
177.2
   
$
2.4
   
$
60.2
   
$
5.2
 

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

   
Gross Presentation
   
Pro forma Net Presentation
 
   
Asset
   
Liability
   
Asset
   
Liability
 
March 31, 2015
 
Position
   
Position
   
Position
   
Position
 
Current position
               
Counterparties with offsetting position
 
$
54.0
   
$
0.6
   
$
53.4
   
$
-
 
Counterparties without offsetting position - assets
   
72.0
     
-
     
72.0
     
-
 
Counterparties without offsetting position - liabilities
   
-
     
-
     
-
     
-
 
     
126.0
     
0.6
     
125.4
     
-
 
Long-term position
                               
Counterparties with offsetting position
   
19.4
     
1.8
     
17.6
     
-
 
Counterparties without offsetting position - assets
   
31.8
     
-
     
31.8
     
-
 
Counterparties without offsetting position - liabilities
   
-
     
-
     
-
     
-
 
     
51.2
     
1.8
     
49.4
     
-
 
Total derivatives
                               
Counterparties with offsetting position
   
73.4
     
2.4
     
71.0
     
-
 
Counterparties without offsetting position - assets
   
103.8
     
-
     
103.8
     
-
 
Counterparties without offsetting position - liabilities
   
-
     
-
     
-
     
-
 
   
$
177.2
   
$
2.4
   
$
174.8
   
$
-
 

December 31, 2014
               
Current position
               
Counterparties with offsetting position
 
$
35.5
   
$
4.4
   
$
31.1
   
$
-
 
Counterparties without offsetting position - assets
   
8.9
     
-
     
8.9
     
-
 
Counterparties without offsetting position - liabilities
   
-
     
0.8
     
-
     
0.8
 
     
44.4
     
5.2
     
40.0
     
0.8
 
Long-term position
                               
Counterparties with offsetting position
   
-
     
-
     
-
     
-
 
Counterparties without offsetting position - assets
   
15.8
     
-
     
15.8
     
-
 
Counterparties without offsetting position - liabilities
   
-
     
-
     
-
     
-
 
     
15.8
     
-
     
15.8
     
-
 
Total derivatives
                               
Counterparties with offsetting position
   
35.5
     
4.4
     
31.1
     
-
 
Counterparties without offsetting position - assets
   
24.7
     
-
     
24.7
     
-
 
Counterparties without offsetting position - liabilities
   
-
     
0.8
     
-
     
0.8
 
   
$
60.2
   
$
5.2
   
$
55.8
   
$
0.8
 

Our payment obligations in connection with substantially all of these hedging transactions are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders.

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 $174.8 million as of March 31, 2015. 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.
 
The following tables reflect amounts recorded in Other Comprehensive Income (“OCI”) 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 Hedging Relationships
 
Three Months Ended March 31,
 
 
2015
   
2014
 
Commodity contracts
 
$
25.2
   
$
(11.9
)

   
Gain (Loss) Reclassified from OCI into Income
(Effective Portion)
 
Location of Gain (Loss)
 
Three Months Ended March 31,
 
   
2015
   
2014
 
Interest expense, net
 
$
-
   
$
(1.3
)
Revenues
   
8.1
     
(6.3
)
   
$
8.1
   
$
(7.6
)
 

Our consolidated earnings are also affected by our 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.
 
   
Gain (Loss) Recognized in Income on Derivatives
 
     
Derivatives Not Designated as Hedging Instruments
Location of Gain Recognized in Income on Derivatives
 
March 31, 2015
   
March 31, 2014
 
Commodity contracts
Revenue
 
$
7.2
   
$
(0.2
)

The following table shows the deferred gains (losses) included in accumulated OCI, which will be reclassified into earnings through the end of 2017 based on year-end valuations.
 
   
March 31, 2015
   
December 31, 2014
 
Commodity hedges (1)
 
$
77.4
   
$
60.3
 
___________
(1) Includes deferred net gains of $53.3 million as of March 31, 2015 related to contracts that will be settled and reclassified to revenue over the next 12 months.

See Note 14 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 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 and option contracts and fixed-price 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 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. This financial position of these derivatives at March 31, 2015, a net asset position of $174.8 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 asset of $132.7 million, ignoring an adjustment for counterparty credit risk. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of $199.2 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 senior secured revolving credit facility (the “TRP Revolver”)  and our accounts receivable securitization facility (the “Securitization Facility”) are based on carrying value, which approximates fair value as the interest rates are based on prevailing market rates; and

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

Fair Value Hierarchy

We categorize the inputs to the fair value measurements of financial assets and liabilities 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, 2015
 
   
Carrying Value
   
Fair 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)
 
$
177.2
   
$
177.2
   
$
-
   
$
172.9
   
$
4.3
 
Liabilities from commodity derivative contracts (1)
   
2.4
     
2.4
     
-
     
1.6
     
0.8
 
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
                                       
Cash and cash equivalents
   
63.5
     
63.5
     
-
     
-
     
-
 
Senior secured revolving credit facility
   
840.0
     
840.0
     
-
     
840.0
     
-
 
Senior unsecured notes
   
4,300.4
     
4,384.9
     
-
     
4,384.9
     
-
 
Accounts receivable securitization facility
   
197.9
     
197.9
     
197.9
     
-
     
-
 
______________
(1) The fair value of our derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 13. 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.

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 market prices for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods.

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

As of March 31, 2015, we had 13 commodity swaps and options contracts categorized as Level 3. The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives are the forward natural gas curves, for which a significant portion of the derivative’s term is beyond available forward pricing. 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 following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy:

   
Commodity Derivative Contracts
(Asset)/Liability
 
Balance, December 31, 2014
   
(1.7
)
Settlements included in Revenue
   
-
 
Unrealized gains included in OCI
   
(1.1
)
Transfers into Level 3
   
(0.6
)
Transfers out of Level 3
   
(0.1
)
Balance, March 31, 2015
 
$
(3.5
)

For the three months ended March 31, 2015, the Partnership transferred $0.1 million in derivative liabilities out of Level 3 and into Level 2. This transfer related to long-term over-the-counter swaps for natural gas and NGL products with deliveries for which observable market prices were available.
 
Note 15 — Related Party Transactions

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.

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

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

   
Three Months Ended March 31,
 
   
2015
   
2014
 
Targa billings of payroll and related costs included in operating expense
 
$
34.9
   
$
29.9
 
Targa allocation of general and administrative expense
   
38.3
     
33.4
 
Cash distributions to Targa based on unit ownership
   
51.6
     
41.5
 
 
Cash contributions from Targa to maintain its 2% general partner ownership
   
53.6
     
2.4
 

Note 16 - Contingencies

Legal Proceedings

Targa Shareholder Litigation

On January 28, 2015, a public shareholder of Targa (the “TRC Plaintiff”) filed a putative class action and derivative lawsuit against Targa (as a nominal defendant), its directors at the time of the ATLS merger (the “TRC Director Defendants”), and ATLS (together with Targa and the TRC Director Defendants, the “TRC Lawsuit Defendants”). This lawsuit is styled Inspired Investors v. Joe Bob Perkins, et al., Cause No. 2015-04961, in the District Court of Harris County, Texas (the “TRC Lawsuit”).
 
The TRC Plaintiff alleged a variety of causes of action challenging the ATLS merger and the disclosures related to the ATLS merger. Generally, the TRC Plaintiff alleged that the TRC Director Defendants breached their fiduciary duties.  The TRC Plaintiff further alleged that the registration statement filed on January 22, 2015 fails to disclose allegedly material details concerning (i) Wells Fargo Securities, LLC’s and the TRC Director Defendants’ supposed conflicts of interest with respect to the ATLS merger, (ii) Targa’s financial projections, (iii) the background of the ATLS merger, and (iv) Wells Fargo Securities, LLC’s analysis of the ATLS merger. The TRC Plaintiff also alleged that Targa overpaid to acquire ATLS.

Based on these allegations, the TRC Plaintiff sought to enjoin the TRC Lawsuit Defendants from proceeding with or consummating the ATLS merger. The TRC Plaintiff also seeks rescission, damages, and attorneys’ fees. On February 25, 2015, the Harris County trial court denied the TRC Plaintiff’s request for a preliminary injunction. The ATLS merger occurred on February 27, 2015.  The TRC Plaintiff has indicated that it intends to dismiss the TRC Lawsuit with prejudice. Should the TRC Plaintiff decide not to dismiss, TRC Lawsuit Defendants will seek dismissal of the TRC Lawsuit.

Atlas Unitholder Litigation

Between October and December 2014, five public unitholders of APL (the “APL Plaintiffs”) filed putative class action lawsuits against APL, ATLS, APL GP, its managers, Targa, the Partnership, the general partner and MLP Merger Sub (the “APL Lawsuit Defendants”). These lawsuits are styled (a) Michael Evnin v. Atlas Pipeline Partners, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania; (b) William B. Federman Family Wealth Preservation Trust v. Atlas Pipeline Partners, L.P., et al., in the District Court of Tulsa County, Oklahoma (the “Tulsa Lawsuit”); (c) Greenthal Living Trust U/A 01/26/88 v. Atlas Pipeline Partners, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania; (d) Mike Welborn v. Atlas Pipeline Partners, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania; and (e) Irving Feldbaum v. Atlas Pipeline Partners, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania, though the Tulsa Lawsuit has since been voluntarily dismissed. The Evnin, Greenthal, Welborn and Feldbaum lawsuits have been consolidated as In re Atlas Pipeline Partners, L.P. Unitholder Litigation, Case No. GD-14-019245, in the Court of Common Pleas for Allegheny County, Pennsylvania (the “Consolidated APL Lawsuit”). In October and November 2014, two public unitholders of ATLS (the “ATLS Plaintiffs” and, together with the APL Plaintiffs, the “Atlas Lawsuit Plaintiffs”) filed putative class action lawsuits against ATLS, ATLS Energy GP, LLC, the general partner of ATLS (“ATLS GP”), its managers, Targa and GP Merger Sub (the “ATLS Lawsuit Defendants” and, together with the APL Lawsuit Defendants, the “Atlas Lawsuit Defendants”). These lawsuits are styled (a) Rick Kane v. Atlas Energy, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania and (b) Jeffrey Ayers v. Atlas Energy, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania (the “ATLS Lawsuits”). The ATLS Lawsuits have been consolidated as In re Atlas Energy, L.P. Unitholder Litigation, Case No. GD-14-019658, in the Court of Common Pleas for Allegheny County, Pennsylvania (the “Consolidated ATLS Lawsuit” and, together with the Consolidated APL Lawsuit, the “Consolidated Atlas Lawsuits”), though the Tulsa lawsuit and the Kane lawsuit have been dismissed.

The Atlas Lawsuit Plaintiffs allege a variety of causes of action challenging the Atlas mergers. Generally, the APL Plaintiffs alleged that (a) APL GP’s managers have breached the covenant of good faith and/or their fiduciary duties and (b) Targa, the Partnership, the general partner, MLP Merger Sub, APL, ATLS and APL GP have aided and abetted in these alleged breaches of the covenant of good faith and/or fiduciary duties. The APL Plaintiffs further alleged that (a) the premium offered to APL’s unitholders is inadequate, (b) APL agreed to contractual terms that will allegedly dissuade other potential acquirers from seeking to acquire APL, and (c) APL GP’s managers favored their self-interests over the interests of APL’s unitholders. The APL Plaintiffs in the Consolidated APL Lawsuit also allege that the registration statement filed on November 19, 2014 fails, among other things, to disclose allegedly material details concerning (i) Stifel, Nicolaus & Company, Incorporated’s analysis of the ATLS merger and APL merger (the “Transactions”); (ii) APL and the Partnership’s financial projections; and (iii) the background of the Transactions. Generally, the ATLS Plaintiffs alleged that (a) ATLS GP’s directors have breached the covenant of good faith and/or their fiduciary duties and (b) Targa, GP Merger Sub, and ATLS have aided and abetted in these alleged breaches of the covenant of good faith and/or fiduciary duties. The ATLS Plaintiffs further alleged that (a) the premium offered to the ATLS unitholders was inadequate, (b) ATLS agreed to contractual terms that would allegedly dissuade other potential acquirers from seeking to acquire ATLS, (c) ATLS GP’s directors favored their self-interests over the interests of the ATLS unitholders and (d) the registration statement failed to disclose allegedly material details concerning, among other things, (i) Wells Fargo Securities, LLC, Stifel, Nicolaus & Company, Incorporated, and Deutsche Bank Securities Inc.’s analyses of the Transactions; (ii) the Partnership, Targa, APL, and ATLS’ financial projections; and (iii) the background of the Transactions.
 
Based on these allegations, the Atlas Lawsuit Plaintiffs sought to enjoin the Atlas Lawsuit Defendants from proceeding with or consummating the Atlas mergers unless and until APL and ATLS adopted and implemented processes to obtain the best possible terms for their respective unitholders. The Atlas Lawsuit Plaintiffs also sought rescission, damages and attorneys’ fees.

The parties to the Consolidated Atlas Lawsuits agreed to settle the Consolidated Atlas Lawsuits on February 9, 2015. In general, the settlements provide that in consideration for the dismissal of the Consolidated Atlas Lawsuits, ATLS and APL will provide supplemental disclosures regarding the Atlas mergers in a filing with the SEC on Form 8-K, which ATLS and APL did on February 11, 2015. The Atlas Lawsuit Defendants agreed to make such supplemental disclosures solely to avoid the uncertainty, risk, burden, and expense inherent in litigation and deny that any supplemental disclosure was or is required under any applicable rule, statute, regulation or law. The parties to the Consolidated Atlas Lawsuits are drafting settlement agreements and expect to seek court approval of the settlements.
 
We are also a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business.

Note 17 — Supplemental Cash Flow Information

   
Three Months Ended March 31,
 
   
2015
   
2014
 
Cash:
       
Interest paid, net of capitalized interest (1)
 
$
28.9
   
$
23.0
 
Income taxes paid, net of refunds
   
0.1
 
   
(0.2
)
Non-cash Investing and Financing balance sheet movements:
               
Deadstock commodity inventories transferred to property, plant and equipment
   
-
     
1.1
 
Accrued distribution equivalent rights on equity awards under share compensation arrangements
   
-
     
0.6
 
Receivables from equity issuances
   
24.6
     
7.1
 
Capital expenditure accruals
   
31.0
     
22.7
 
Transfers from materials and supplies inventory to property, plant and equipment
   
0.6
     
0.4
 
Change in ARO liability and property, plant and equipment due to revised future ARO cash flow estimate
   
3.7
     
2.1
 
___________
(1) Interest capitalized on major projects was $2.4 million and $6.9 million for three months ended March 31, 2015 and 2014.
 
See Note 4 for information on non-cash transaction related to the Atlas mergers.
 
Note 18 — Segment Information

We report our operations in two divisions: (i) Gathering and Processing, consisting of two reportable segments – (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing consisting of two reportable segments – (a) Logistics Assets and (b) Marketing and Distribution. The financial results of our hedging activities on reported profits are reported in Other.

Our Gathering and Processing division 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 Field Gathering and Processing segment's assets are located in North Texas, the Permian Basin of West Texas and Southeast New Mexico, South Texas, Oklahoma, Kansas and in North Dakota. The Coastal Gathering and Processing segment's assets are located in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and Marketing division is also referred to as our Downstream Business. Our Downstream Business 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, refined petroleum products and crude oil. It also includes certain natural gas supply and marketing activities in support of our other operations, including services to LPG exporters, as well as transporting natural gas and NGLs.
 
Our Logistics Assets segment is involved in transporting, storing, and fractionating mixed NGLs; storing, terminaling, and transporting finished NGLs, including services for the LPG export market; and storing and terminaling refined petroleum products. These assets are generally connected to and supplied in part by our Gathering and Processing segments and are predominantly located in Mont Belvieu and Galena Park, Texas and Lake Charles, Louisiana.

Our Marketing and Distribution segment covers activities required to distribute and market raw and finished NGLs and all natural gas marketing activities. It includes (1) marketing our own NGL production and purchasing NGL products for resale in selected United States markets; (2) providing LPG balancing services to refinery customers; (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end-users; (4) providing propane, butane and services to LPG exporters; and (5) marketing natural gas available to us from our Gathering and Processing division and the purchase and resale and other value added activities related to third-party natural gas in selected United States markets.

Other contains the results of our commodity hedging activities included in operating margin. Eliminations of inter-segment transactions are reflected in the corporate and eliminations column.

We are reviewing our segment disclosures as a result of the merger and integration efforts related to the Atlas mergers.

Our reportable segment information is shown in the following tables:

   
Three Months Ended March 31, 2015
 
   
Field Gathering and Processing
   
Coastal Gathering and Processing
   
Logistics Assets
   
Marketing and Distribution
   
Other
   
Corporate and Eliminations
   
Total
 
Revenues
                           
Sales of commodities
 
$
168.0
   
$
52.7
   
$
27.4
   
$
1,132.3
   
$
21.7
   
$
0.1
   
$
1,402.2
 
Fees from midstream services
   
63.3
     
8.8
     
87.7
     
117.7
     
-
     
-
     
277.5
 
     
231.3
     
61.5
     
115.1
     
1,250.0
     
21.7
     
0.1
     
1,679.7
 
Intersegment revenues