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EX-31.1 - EXHIBIT 31.1 - Targa Resources Partners LPex31_1.htm
EX-31.2 - EXHIBIT 31.2 - Targa Resources Partners LPex31_2.htm
EX-32.1 - EXHIBIT 32.1 - Targa Resources Partners LPex32_1.htm
EX-32.2 - EXHIBIT 32.2 - Targa Resources Partners LPex32_2.htm
EX-12.1 - EXHIBIT 12.1 - Targa Resources Partners LPex12_1.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 September 30, 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 No

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

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

As of October 30, 2015, there were 184,847,901 common units representing limited partner interests and 3,772,406 general partner units outstanding. As of October 30, 2015, there were 5,000,000 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units outstanding.
 

 

PART I—FINANCIAL INFORMATION
 
   
4
   
4
   
5
   
6
   
7
   
8
   
9
   
36
   
63
   
68
   
PART II—OTHER INFORMATION
 
   
68
   
68
   
69
   
69
   
69
   
69
   
70
   
SIGNATURES
 
   
71
 
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 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 on 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 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 Offered 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

September 30,
2015
   
December 31,
2014
 
     
(Unaudited)
(In millions)
 
   
ASSETS
 
Current assets:
         
Cash and cash equivalents
   
$
92.8
   
$
72.3
 
Trade receivables, net of allowances of $0.0 million
     
620.5
     
566.8
 
Inventories
     
151.1
     
168.9
 
Assets from risk management activities
     
92.3
     
44.4
 
Other current assets
     
8.7
     
3.8
 
Total current assets
     
965.4
     
856.2
 
Property, plant and equipment
     
11,791.6
     
6,514.3
 
Accumulated depreciation
     
(2,041.4
)
   
(1,689.7
)
Property, plant and equipment, net
     
9,750.2
     
4,824.6
 
Goodwill
     
551.4
     
-
 
Intangible assets, net
     
1,695.7
     
591.9
 
Long-term assets from risk management activities
     
45.4
     
15.8
 
Investments in unconsolidated affiliates
     
264.2
     
50.2
 
Other long-term assets
     
50.9
     
38.5
 
Total assets
   
$
13,323.2
   
$
6,377.2
 
                      
LIABILITIES AND OWNERS' EQUITY
 
Current liabilities: 
                 
Accounts payable and accrued liabilities
   
$
650.5
   
$
592.7
 
Accounts payable to Targa Resources Corp.
     
39.5
     
53.2
 
Liabilities from risk management activities
     
4.3
     
5.2
 
Accounts receivable securitization facility
     
135.5
     
182.8
 
Total current liabilities
     
829.8
     
833.9
 
Long-term debt
     
5,336.4
     
2,783.4
 
Long-term liabilities from risk management activities
     
4.0
     
-
 
Deferred income taxes, net
     
22.1
     
13.7
 
Other long-term liabilities
     
73.7
     
57.8
 
                 
Contingencies (see Note 16)
                 
                 
Owners' equity:
                 
Limited partners
 
Issued
   
Outstanding
       
4,931.5
     
2,384.1
 
September 30, 2015
  185,049,203     184,847,487                    
December 31, 2014
  118,652,798     118,586,056                    
General partner
     
1,747.5
     
78.6
 
September 30, 2015
  3,772,397     3,772,397                    
December 31, 2014
  2,420,124     2,420,124                    
Receivables from unit issuances
     
-
     
(1.0
)
Accumulated other comprehensive income (loss)
     
78.6
     
60.3
 
Treasury units at cost (201,716 units as of September 30, 2015, and 66,742 as of December 31, 2014)
     
(10.0
)
   
(4.8
)
       
6,747.6
     
2,517.2
 
Noncontrolling interests in subsidiaries
     
309.6
     
171.2
 
Total owners' equity
     
7,057.2
     
2,688.4
 
Total liabilities and owners' equity
   
$
13,323.2
   
$
6,377.2
 
 
See notes to consolidated financial statements.
 
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS

   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2015
   
2014
   
2015
   
2014
 
   
(Unaudited)
 
   
(In millions, except per unit amounts)
 
Revenues:
               
Sales of commodities
 
$
1,321.3
   
$
2,009.2
   
$
4,119.6
   
$
5,853.3
 
Fees from midstream services
   
310.8
     
279.1
     
891.6
     
730.4
 
Total revenues
   
1,632.1
     
2,288.3
     
5,011.2
     
6,583.7
 
Costs and expenses:
                               
Product purchases
   
1,172.4
     
1,880.5
     
3,677.7
     
5,412.2
 
Operating expenses
   
133.6
     
112.8
     
381.8
     
323.6
 
Depreciation and amortization expenses
   
165.8
     
87.5
     
448.3
     
252.8
 
General and administrative expenses
   
42.9
     
40.4
     
130.1
     
115.3
 
Other operating (income) expense
   
0.1
     
(4.3
)
   
0.6
     
(5.3
)
Income from operations
   
117.3
     
171.4
     
372.7
     
485.1
 
Other income (expense):
                               
Interest expense, net
   
(64.1
)
   
(36.0
)
   
(177.2
)
   
(104.1
)
Equity earnings (loss)
   
(1.6
)
   
4.7
     
(1.1
)
   
13.8
 
Loss from financing activities (see Note 10)
   
(0.5
)
   
-
     
(0.5
)
   
-
 
Other
   
1.8
     
(0.6
)
   
(9.1
)
   
(0.6
)
Income before income taxes
   
52.9
     
139.5
     
184.8
     
394.2
 
Income tax (expense) benefit:
                               
Current
   
(0.2
)
   
(0.9
)
   
(0.7
)
   
(2.6
)
Deferred
   
0.6
     
(0.4
)
   
0.3
     
(1.1
)
     
0.4
     
(1.3
)
   
(0.4
)
   
(3.7
)
Net income
   
53.3
     
138.2
     
184.4
     
390.5
 
Less: Net income attributable to noncontrolling interests
   
4.8
     
9.9
     
17.3
     
30.9
 
Net income attributable to Targa Resources Partners LP
 
$
48.5
   
$
128.3
   
$
167.1
   
$
359.6
 
                                 
Net income attributable to general partner
 
$
44.9
   
$
38.6
   
$
132.0
   
$
108.2
 
Net income attributable to limited partners
   
3.6
     
89.7
     
35.1
     
251.4
 
Net income attributable to Targa Resources Partners LP
 
$
48.5
   
$
128.3
   
$
167.1
   
$
359.6
 
                                 
Net income per limited partner unit - basic
 
$
0.02
   
$
0.78
   
$
0.21
   
$
2.21
 
Net income per limited partner unit - diluted
 
$
0.02
   
$
0.78
   
$
0.21
   
$
2.20
 
Weighted average limited partner units outstanding - basic
   
184.8
     
115.1
     
168.1
     
113.9
 
Weighted average limited partner units outstanding - diluted
   
185.1
     
115.7
     
168.5
     
114.5
 

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

   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2015
   
2014
   
2015
   
2014
 
   
(Unaudited)
 
   
(In millions)
 
Net income
 
$
53.3
   
$
138.2
   
$
184.4
   
$
390.5
 
Other comprehensive income (loss):
                               
Commodity hedging contracts:
                               
Change in fair value
   
42.9
     
14.2
     
59.4
     
(4.5
)
Settlements reclassified to revenues
   
(16.7
)
   
0.8
     
(41.1
)
   
11.6
 
Interest rate swaps:
                               
Settlements reclassified to interest expense, net
   
-
     
-
     
-
     
2.4
 
Other comprehensive income (loss)
   
26.2
     
15.0
     
18.3
     
9.5
 
Comprehensive income (loss)
   
79.5
     
153.2
     
202.7
     
400.0
 
Less: Comprehensive income attributable to noncontrolling interests
   
4.8
     
9.9
     
17.3
     
30.9
 
Comprehensive income attributable to Targa Resources Partners LP
 
$
74.7
   
$
143.3
   
$
185.4
   
$
369.1
 
 
See notes to consolidated financial statements.
 
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY

   
Limited
Partner
   
General
Partner
   
Receivables
From Unit
   
Accumulated
Other
Comprehensive
   
Treasury
Units
   
Non-
controlling
     
   
Common
   
Amount
   
Units
   
Amount
   
Issuances
   
Income (Loss)
   
Units
   
Amount
   
Interests
   
Total
 
   
(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
   
-
     
12.8
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
12.8
 
Distribution equivalent rights
   
-
     
(1.9
)
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
(1.9
)
Issuance of common units under compensation program
   
405
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
 
Units tendered for tax withholding obligations
   
(135
)
   
-
     
-
     
-
     
-
     
-
     
135
     
(5.2
)
   
-
     
(5.2
)
Equity offerings
   
7,377
     
315.4
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
315.4
 
Acquisition of APL
   
58,614
     
2,583.1
     
-
     
-
     
-
     
-
     
-
     
-
     
113.4
     
2,696.5
 
Contributions from Targa Resources Corp.
   
-
     
-
     
1,352
     
59.1
     
1.0
     
-
     
-
     
-
     
-
     
60.1
 
Distributions to noncontrolling interests
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
(8.7
)
   
(8.7
)
Contributions from noncontrolling interests
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
16.4
     
16.4
 
Other comprehensive income (loss)
   
-
     
-
     
-
     
-
     
-
     
18.3
     
-
     
-
     
-
     
18.3
 
Net income
   
-
     
35.1
     
-
     
132.0
     
-
     
-
     
-
     
-
     
17.3
     
184.4
 
Distributions
   
-
     
(397.1
)
   
-
     
(134.6
)
   
-
     
-
     
-
     
-
     
-
     
(531.7
)
Targa contribution  - Special General Partner Interest (see Note 2)
   
-
     
-
     
-
     
1,612.4
     
-
     
-
     
-
     
-
     
-
     
1,612.4
 
Balance September 30, 2015
   
184,847
   
$
4,931.5
     
3,772
   
$
1,747.5
   
$
-
   
$
78.6
     
202
   
$
(10.0
)
 
$
309.6
   
$
7,057.2
 
                                                                                 
Balance December 31, 2013
   
111,263
   
$
2,001.9
     
2,271
   
$
62.0
   
$
-
   
$
(6.1
)
   
-
   
$
-
   
$
160.6
   
$
2,218.4
 
Compensation on equity grants
   
-
     
7.0
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
7.0
 
Distribution equivalent rights
   
-
     
(2.0
)
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
(2.0
)
Issuance of common units under compensation program
   
214
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
 
Units tendered for tax withholding obligations
   
(67
)
   
-
     
-
     
-
     
-
     
-
     
67
     
(4.8
)
   
-
     
(4.8
)
Equity offerings
   
4,364
     
257.2
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
257.2
 
Contributions from Targa Resources Corp.
   
-
     
-
     
92
     
5.6
     
(0.4
)
   
-
     
-
     
-
     
-
     
5.2
 
Distributions to noncontrolling interests
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
(26.8
)
   
(26.8
)
Other comprehensive income (loss)
   
-
     
-
     
-
     
-
     
-
     
9.5
     
-
     
-
     
-
     
9.5
 
Net income
   
-
     
251.4
     
-
     
108.2
     
-
     
-
     
-
     
-
     
30.9
     
390.5
 
Distributions
   
-
     
(260.7
)
   
-
     
(102.1
)
   
-
     
-
     
-
     
-
     
-
     
(362.8
)
Balance September 30, 2014
   
115,774
   
$
2,254.8
     
2,363
   
$
73.7
   
$
(0.4
)
 
$
3.4
     
67
   
$
(4.8
)
 
$
164.7
   
$
2,491.4
 
 
See notes to consolidated financial statements.
 
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS

   
Nine Months Ended September 30,
 
   
2015
   
2014
 
 
(Unaudited)
 
   
(In millions)
 
Cash flows from operating activities
       
Net income
 
$
184.4
   
$
390.5
 
Adjustments to reconcile net income to net cash provided by operating activities:
               
Amortization in interest expense
   
9.3
     
8.8
 
Compensation on equity grants
   
12.8
     
7.0
 
Depreciation and amortization expense
   
448.3
     
252.8
 
Accretion of asset retirement obligations
   
3.9
     
3.3
 
Deferred income tax expense (benefit)
   
(0.3
)
   
1.1
 
Equity (earnings) loss of unconsolidated affiliates
   
1.1
     
(13.8
)
Distributions received from unconsolidated affiliates
   
10.1
     
13.8
 
Risk management activities
   
53.2
     
0.9
 
(Gain) loss on sale or disposition of assets
   
(0.2
)
   
(5.6
)
Loss from financing activities
   
0.5
     
-
 
Changes in operating assets and liabilities, net of business acquisitions:
               
Receivables and other assets
   
126.7
     
(40.4
)
Inventory
   
31.2
     
(115.5
)
Accounts payable and other liabilities
   
(143.2
)
   
68.9
 
Net cash provided by operating activities
   
737.8
     
571.8
 
Cash flows from investing activities
               
Outlays for property, plant and equipment
   
(625.3
)
   
(571.7
)
Business acquisition, net of cash acquired
   
(828.7
)
   
-
 
Investment in unconsolidated affiliates
   
(6.6
)
   
-
 
Return of capital from unconsolidated affiliates
   
1.1
     
4.2
 
Other, net
   
(3.0
)
   
6.3
 
Net cash used in investing activities
   
(1,462.5
)
   
(561.2
)
Cash flows from financing activities
               
Proceeds from borrowings under credit facility
   
1,646.0
     
1,295.0
 
Repayments of credit facility
   
(1,211.0
)
   
(1,115.0
)
Borrowings from accounts receivable securitization facility
   
275.5
     
88.9
 
Repayments of accounts receivable securitization facility
   
(322.8
)
   
(131.0
)
Proceeds from issuance of senior notes
   
1,700.0
     
-
 
Redemption of APL senior notes
   
(1,168.8
)
   
-
 
Costs in connection with financing arrangements
   
(20.7
)
   
(2.7
)
Proceeds from sale of common units
   
318.6
     
259.9
 
Repurchase of common units under compensation plans
   
(5.2
)
   
(4.8
)
Contributions received from General Partner
   
60.1
     
5.2
 
Contributions received from noncontrolling interests
   
16.4
     
-
 
Distributions paid to unitholders
   
(531.7
)
   
(362.8
)
Payment of distribution equivalent rights
   
(2.5
)
   
(1.6
)
Distributions paid to noncontrolling interests
   
(8.7
)
   
(26.8
)
Net cash provided by financing activities
   
745.2
     
4.3
 
Net change in cash and cash equivalents
   
20.5
     
14.9
 
Cash and cash equivalents, beginning of period
   
72.3
     
57.5
 
Cash and cash equivalents, end of period
 
$
92.8
   
$
72.4
 

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 September 30, 2015, Targa owned a 10.6% interest in us in the form of 3,772,397 general partner units and 16,309,594 common units. In addition, Targa Resources GP LLC also owns our 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-Partnership Units and Related Matters).

In connection with the Atlas mergers (see Note 4-Business Acquisitions), 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 consideration paid by Targa for and resulting tax basis in the Atlas Pipeline Partners GP, LLC, a Delaware limited liability company and the general partner of APL (“APL GP”) acquired in the ATLS merger (see Note 4 – Business Acquisitions). The Special GP Interest is not entitled to current distributions or allocations of net income or loss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL GP and the right to receive distributions in liquidation.

In connection with our issuance of 5,000,000 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) in October 2015, our Partnership Agreement was amended and restated for the purpose of defining the preferences, rights, powers and duties of holders of our Preferred Units (see Note 11-Partnership Units and Related Matters).

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-Segment Information for certain financial information for our business segments.

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’s centralized general and administrative services.
 
Subsequent Event

On November 2, 2015, we and Targa entered into an Agreement and Plan of Merger, by and among Targa, Spartan Merger Sub LLC, a subsidiary of Targa (“Merger Sub”), us and our general partner pursuant to which Targa will acquire all of our outstanding common units representing limited partner interests in us not already owned by Targa or its subsidiaries. Upon the terms and conditions set forth in the Merger Agreement, Merger Sub will be merged with and into us, with us continuing as the surviving entity and as a subsidiary of Targa (see Note 19 - Buy-in Acquisition).

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 equity holders. For GAAP reporting purposes, these two mergers are viewed as a single integrated transaction. As such, the financial effects of the Targa consideration related to the ATLS merger have been reflected in these financial statements. As described in Note 1, our Partnership Agreement was amended to provide for the issuance of the Special GP Interest in us equal to the tax basis of the APL GP Interests acquired in the ATLS merger totaling $1.6 billion. The Special GP Interest is not entitled to current distributions or allocations of net income or loss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL GP and the right to distributions in liquidation.

The unaudited consolidated financial statements for the three and nine months ended September 30, 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 and nine months ended September 30, 2015 are not necessarily indicative of the results that may be expected for the full year.

Note 3 — Significant Accounting Policies

Accounting Policy Updates

The accounting policies that we follow are set forth in Note 3 of the Notes to Consolidated Financial Statements in our Annual Report. We have updated our policies during the nine months ended September 30, 2015 to include our accounting policy for goodwill related to the Atlas mergers.

Goodwill

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.

Goodwill is subject to a test for impairment at least annually, as well as 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 by revisiting our consolidation model for each of our less-than-wholly owned subsidiaries.
 
In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The amendments in this update require that debt issuance costs related to a recognized debt liability (other than revolving credit facilities) be presented in the consolidated balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This update deals solely with financial statement display matters; recognition and measurement of debt issuance costs are unaffected. Unamortized debt issuance costs of $40.2 million and $29.9 million for term loans and notes were included in Other long-term assets on the Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014. In August 2015, the FASB issued ASU 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. The amendment clarifies ASU 2015-03 and provides that an entity may defer and present debt issuance costs for a line-of-credit or other revolving credit facility arrangement as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the arrangement. Unamortized debt issuance costs of $6.5 million and $7.6 million for revolving credit facilities were included in Other long-term assets on the Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014. We will continue to include debt issuance costs for our line-of-credit and revolving credit facility arrangements in Other long-term assets upon adoption of ASU 2015-03. We plan to adopt these standards as of December 31, 2015.

In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 303): Simplifying the Measurement of Inventory. Topic 303 currently requires inventory to be measured at the lower of cost or market, where market could be replacement cost, net realizable value or net realizable value less a normal profit margin. The amendments in this update require that all inventory, excluding inventory that is measured using the last-in, first-out method or the retail inventory method, be measured at the lower of cost or net realizable value. Net realizable value is defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This amendment has been adopted, with no impact on our consolidated financial statements or results of operations.

In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date. The amendment defers the effective date of ASU 2014-09, Revenue from Contracts with Customers (Topic 606) by one year. As a result of the amendment, Topic 606 is effective for the annual period beginning December 15, 2017, and for annual and interim periods thereafter, with early adoption permitted. Earlier adoption is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We expect to adopt this guidance on January 1, 2018 and are continuing to evaluate the impact of Topic 606 on our revenue recognition practices.

In September 2015, the FASB issued ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments. Topic 805 currently requires that adjustments to provisional amounts recorded in a business combination be recognized retrospectively as if the accounting had been completed at the acquisition date. The amendments in this update require that an acquirer recognize these measurement-period adjustments in the reporting period in which the adjustment amounts are determined, with the effect on earnings of changes in depreciation, amortization or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments require disclosure of the amount recorded in current-period earnings that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The amendments are effective for us in 2016, with early adoption permitted. We adopted the amendments on September 30, 2015 and have recognized the measurement-period adjustments for the Atlas mergers determined in the three months ended September 30, 2015 in current period earnings. See Note 4 for additional information regarding the nature and amount of the measurement-period adjustments.
 
Note 4 –Business Acquisitions

2015 Acquisition

Atlas Mergers
 
On February 27, 2015, (i) Targa completed the transactions contemplated by the Agreement and Plan of Merger, dated as of October 13, 2014 (the “ATLS Merger Agreement”), by and among 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 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 APL GP. Pursuant to the terms and conditions set forth in the ATLS Merger Agreement, GP Merger Sub merged (the “ATLS merger”) with and into ATLS, with ATLS continuing as the surviving entity and as a subsidiary of Targa. Pursuant to the terms and conditions set forth in the APL Merger Agreement, MLP Merger Sub merged (the “APL merger” and, together with the ATLS merger, the “Atlas mergers”) with and into APL, with APL continuing as the surviving entity and as a subsidiary of the Partnership.
 
While the Atlas mergers were two separate legal transactions, for GAAP reporting purposes, they are viewed as a single integrated transaction.  As such, the financial effects of the ATLS Merger Consideration (as defined below) paid by Targa have been reflected in these financial statements.

In connection with the Atlas mergers, APL changed its name to “Targa Pipeline Partners LP,” which we refer to as TPL, and ATLS changed its name to “Targa Energy LP.”
 
In addition, prior to the completion of the Atlas mergers, ATLS, pursuant to a separation and distribution agreement entered into by and among ATLS, ATLS GP and Atlas Energy Group, LLC, a Delaware limited liability company (“AEG”), on February 27, 2015, (i) transferred its assets and liabilities other than those related to its “Atlas Pipeline Partners” segment, to AEG and (ii) effected a pro 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).
 
Pursuant to the APL Merger Agreement, our general partner entered into an amendment to our Partnership Agreement, which we refer to as the IDR Giveback Amendment, in order to reduce aggregate distributions to TRC, as the holder of the Partnership’s 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. In total, TPL adds 2,053 MMcf/d of processing capacity and 12,220 miles of additional pipeline. The results of TPL are 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 Consideration, the “APL Merger Consideration”), a $128.0 million total cash payment, of which $0.6 million was expensed at the acquisition date as the cash payment representing accelerated vesting of a portion of retained employees’ APL phantom awards. We issued 58,614,157 of our common units and awarded 629,231 replacement phantom unit awards with a combined value of approximately $2.6 billion as consideration for the APL merger (based on the $43.82 closing market price of a common unit on the NYSE on February 27, 2015). The cash component of the APL merger also included $701.4 million for the mandatory repayment and extinguishment at closing of the APL Senior Secured Revolving Credit Facility that was to mature in May 2017 (the “APL Revolver”), $28.8 million of payments related to change of control and $6.4 million of cash paid in lieu of unit issuances in connection with settlement of APL equity awards for AEG employees. In March 2015, Targa contributed $52.4 million to us to maintain its 2% general partner interest.
 
In addition, pursuant to the APL Merger Agreement, APL exercised its right under the certificate of designations of the APL 8.25% Class E cumulative redeemable perpetual preferred units (“Class E Preferred Units”) to redeem the APL Class E Preferred Units immediately prior to the effective time of the APL merger.
 
The ATLS merger was a stock-for-unit transaction with an exchange ratio of 0.1809 of Targa common stock, par value $0.001 per share (the “ATLS Stock Consideration”), and $9.12 in cash for each ATLS common unit (the ATLS Cash Consideration” and, with the ATLS Stock Consideration, the “ATLS Merger Consideration”), (a $514.7 million total cash payment). Targa issued 10,126,532 of its common shares and awarded 81,740 replacement restricted stock units with a combined value of approximately $1.0 billion for the ATLS merger (based on the $99.58 closing market price of a TRC common share on the NYSE on February 27, 2015). The cash component of the ATLS merger also included approximately $149.2 million of payments related to change of control and cash settlements of equity awards, $88.0 million for repayment of a portion of ATLS outstanding indebtedness and $11.0 million for reimbursement of certain transaction expenses. Approximately $4.5 million of the one-time cash payments and cash settlements of equity awards, which represent accelerated vesting of a portion of retained employees’ ATLS phantom units, were expensed at the acquisition date.
 
ATLS owned, directly and indirectly, 5,754,253 APL common units immediately prior to closing. Targa’s acquisition of ATLS resulted in Targa acquiring these common units (converted to 3,363,935 of our common units) valued at approximately $147.4 million (based on the $43.82 closing market price of our common units on the NYSE on February 27, 2015) and the right to receive the units’ one-time cash payment of approximately $7.3 million, which reduced the consolidated purchase price by approximately $154.7 million.
 
All outstanding ATLS equity awards, whether vested or unvested, were adjusted in connection with the Spin-Off on the terms and conditions set forth in an Employee Matters Agreement entered into by ATLS, ATLS GP and AEG on February 27, 2015. Following the Spin-Off-related adjustment and at the effective time of the ATLS merger, each outstanding ATLS option and ATLS phantom unit award, whether vested or unvested, held by a person who became an employee of AEG became fully vested (to the extent not vested) and was cancelled and converted into the right to receive the ATLS Merger Consideration in respect of each ATLS common unit underlying the ATLS option or phantom unit award (in the case of options, net of the applicable exercise price). Each outstanding vested ATLS option held by an employee of APL who became an employee of Targa in connection with the Atlas Transactions (a “Midstream Employee”) was cancelled and converted into the right to receive the ATLS Merger Consideration in respect of each ATLS common unit underlying the vested ATLS option, net of the applicable exercise price. Each outstanding unvested ATLS option and each outstanding ATLS phantom unit award held by a Midstream Employee was cancelled and converted into the right to receive (1) the ATLS Cash Consideration in respect of each ATLS common unit underlying such ATLS option or phantom unit award and (2) a TRC restricted stock unit award with respect to a number of shares of TRC Common Stock equal to the product of the ATLS Stock Consideration multiplied by the number of ATLS common units underlying such ATLS option or phantom unit award (in the case of options, net of the applicable exercise price).
 
In connection with the APL merger, each outstanding APL phantom unit award held by an employee of AEG became fully vested and was cancelled and converted into the right to receive the APL Merger Consideration in respect of each APL common unit underlying the APL phantom unit award. Each outstanding APL phantom unit award held by a Midstream Employee was cancelled and converted into the right to receive (1) the APL Cash Consideration in respect of each APL common unit underlying such APL phantom unit award and (2) a Partnership phantom unit award with respect to a number of our common units equal to the product of the APL Unit Consideration multiplied by the number of APL common units underlying such APL phantom unit award.
 
The acquired business contributed revenues of $1,065.7 million and a net loss of $1.0 million to us for the period from February 27, 2015 to September 30, 2015, and is reported in our Field Gathering and Processing segment. In 2015, we incurred $14.9 million of acquisition-related costs. These expenses are included in other expense in our Consolidated Statements of Operations for the nine months ended September 30, 2015.
 
Pro Forma Impact of Atlas Mergers on Consolidated Statements of Operations

The following summarized unaudited pro forma consolidated statement of operations information for the nine months ended September 30, 2015 and September 30, 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 these acquisitions as of January 1, 2014, or that the results that will be attained in the future.
 
   
Pro Forma Results for the Nine Months Ended
 
   
September 30, 2015
   
September 30, 2014
 
Revenues
 
$
5,299.9
   
$
8,659.5
 
Net income
   
178.1
     
462.1
 

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 depreciation expense resulting from the difference between the historical balances of APL’s property, plant and equipment, net, and our preliminary estimate of the fair value of property, plant and equipment 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 Long Term Incentive Plan (“LTIP”) awards which were issued in connection with the acquisition to APL phantom unitholders who continue to provide service as Targa employees following the completion of the APL merger.
 
· 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 to Atlas Resource Partners, L.P. of 100% of APL’s interest in gas gathering assets located in the Appalachian Basin of Tennessee.
 
· Exclude $14.9 million of acquisition-related costs incurred in 2015 from pro forma net income for the nine months ended September 30, 2015. Pro forma net income for the nine months ended September 30, 2014 was adjusted to include these charges.
 
· Conform to our accounting policy, we also adjusted APL’s revenues to report plant sales of Y-grade at contractual net values rather than grossed up for transportation and fractionation deduction factors.
 
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 paid, 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 by Targa for APL:
 
Cash paid, net of cash acquired (2)
 
$
828.7
 
Common units of TRP
   
2,568.5
 
Replacement phantom units awarded (3)
   
15.0
 
Total
 
$
3,412.2
 
Total fair value of consideration transferred
 
$
5,024.2
 
 

(1) Targa acquired $5.5 million of cash.
(2) We acquired $35.3 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 $551.4 million, which was recorded as goodwill. This determination is based on our preliminary valuation and is subject to revisions pending the completion of the valuation and other adjustments.

Preliminary fair value determination:
 
February 27, 2015
 
Trade and other current receivables, net
 
$
181.1
 
Other current assets
   
24.5
 
Assets from risk management activities
   
102.1
 
Property, plant and equipment
   
4,703.1
 
Investments in unconsolidated affiliates
   
219.7
 
Intangible assets
   
1,199.0
 
Other long-term assets
   
5.6
 
Current liabilities
   
(257.5
)
Long-term debt
   
(1,573.3
)
Deferred income tax liabilities, net
   
(8.6
)
Other long-term liabilities
   
(9.0
)
Total identifiable net assets
   
4,586.7
 
Noncontrolling interest in subsidiaries
   
(113.4
)
Current liabilities retained by Targa
   
(0.5
)
Goodwill
   
551.4
 
   
$
5,024.2
 

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 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 preliminary pending completion of final valuations. As a result, goodwill is also preliminary, as it has been recorded as the excess of the purchase price over the estimated fair value of net assets acquired.
 
During the three months ended June 30, 2015, we recorded measurement period adjustments to our preliminary acquisition date fair values due to the refinement of our valuation models, assumptions and inputs. As a result, the statement of operations for the three months ended March 31, 2015 was retrospectively adjusted for the impact of measurement-period adjustments to property, plant and equipment, intangible assets, and investment in unconsolidated affiliates. These adjustments resulted in a decrease in depreciation and amortization expense of $1.0 million, and an increase in equity earnings of $0.3 million from the amounts previously reported in our Form 10-Q for the quarter ended March 31, 2015.

During the three months ended September 30, 2015, we recorded additional measurement-period adjustments to our preliminary acquisition date fair values due to the refinement of our valuation models, assumptions and inputs. In accordance with the recent ASU 2015-16, we have recognized these measurement-period adjustments in the current reporting period, with the effect on the consolidated statements of operations resulting from the change to the provisional amounts calculated as if the acquisition had been completed at February 27, 2015. During the three months ended September 30, 2015, the acquisition date fair value of property, plant and equipment increased by $9.9 million, investments in unconsolidated affiliates increased by $5.5 million, intangible assets decreased by $5.0 million, current liabilities increased by $2.4 million, other assets decreased by $1.0 million, and other current assets decreased by $0.6 million, which resulted in a decrease in goodwill of $6.4 million. These adjustments resulted in increased revenues of $0.6 million, a reduction of operating expenses of $1.9 million, depreciation and amortization expense of $0.1 million and equity losses of $0.1 million recorded in the three months ended September 30, 2015, which under the prior accounting standard would have been reflected in previous reporting periods.

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 $551.4 million is attributable to the workforce of the acquired business and the expected synergies with us and Targa. The goodwill is expected to be amortizable for tax purposes. The attribution of the goodwill to reporting units for the purpose of required future impairment assessments will be completed in conjunction with our finalization of the fair value determination.

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

See Note 10-Debt Obligations 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. The fair value of the remaining contingent payment is recorded within other long term liabilities on our Consolidated Balance Sheets. The range of the undiscounted amount that we could pay related to the remaining contingent payment is between $0.0 and $6.0 million. We finalized our acquisition analysis and modeling of this contingent liability during the three months ended June 30, 2015, which resulted in an acquisition date fair value of $4.2 million. Any future change in the fair value of this liability will be included in earnings.
 
Replacement Phantom Units

In connection with the Atlas mergers, we awarded replacement phantom units in accordance with and as required by the Atlas Merger Agreements to those APL employees who became Targa employees after the acquisition. The vesting dates and terms remained 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 compensation expense, respectively. Compensation cost will be recognized in general and administrative expense over the remaining service period of each award.

Note 5 — Inventories

   
September 30, 2015
   
December 31, 2014
 
Commodities
 
$
138.4
   
$
157.4
 
Materials and supplies
   
12.7
     
11.5
 
   
$
151.1
   
$
168.9
 

Note 6 — Property, Plant and Equipment and Intangible Assets

   
September 30, 2015
   
December 31, 2014
   
Estimated useful life
(In Years)
 
Gathering systems
 
$
6,187.7
   
$
2,588.6
   
5 to 20
 
Processing and fractionation facilities
   
2,989.8
     
1,884.1
   
5 to 25
 
Terminaling and storage facilities
   
1,098.2
     
1,038.9
   
5 to 25
 
Transportation assets
   
439.5
     
359.0
   
10 to 25
 
Other property, plant and equipment
   
213.5
     
149.1
   
3 to 25
 
Land
   
108.5
     
95.6
    -  
Construction in progress
   
754.4
     
399.0
   
-
 
Property, plant and equipment
   
11,791.6
     
6,514.3
         
Accumulated depreciation
   
(2,041.4
)
   
(1,689.7
)
       
Property, plant and equipment, net
 
$
9,750.2
   
$
4,824.6
         
                         
Intangible assets
 
$
1,880.6
   
$
681.8
   
20
 
Accumulated amortization
   
(184.9
)
   
(89.9
)
       
Intangible assets, net
 
$
1,695.7
   
$
591.9
         

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

The fair values of intangible assets acquired in the Atlas mergers have been recorded at a preliminary value of $1,199.0 million pending completion of final valuations. For the purpose of our preparing the accompanying consolidated financial statements (which includes seven months of amortization of these intangible assets) we have amortized these intangible assets over a 20 year life using a straight-line method.
 
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 preliminary Atlas valuation and straight-line treatment, is approximately $129.9 million, $148.1 million, $141.3 million, $127.6 million and $116.6 million for each of the years 2015 through 2019.
 
Note 7 — Asset Retirement Obligations

Our asset retirement obligations (“ARO”) primarily relate to certain gas gathering pipelines and processing facilities, and are included in our Consolidated Balance Sheets as a component of other long-term liabilities. The changes in our ARO are as follows:
 
   
Nine Months Ended
September 30, 2015
 
Beginning of period
 
$
56.8
 
Preliminary fair value of ARO acquired with the APL merger
   
4.0
 
Change in cash flow estimate
   
3.8
 
Accretion expense
   
3.9
 
End of period
 
$
68.5
 

Note 8 — Investments in Unconsolidated Affiliates

Our unconsolidated investments consist of a 38.8% non-operated ownership interest in Gulf Coast Fractionators LP (“GCF”) and three non-operated joint ventures in South Texas acquired in the Atlas merger; 75% interest in T2 LaSalle; 50% interest in T2 Eagle Ford; and 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 consolidated 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:
 
   
Nine Months Ended September 30, 2015
 
   
GCF
   
T2 Joint Ventures
   
Total
 
Beginning of period
 
$
50.2
   
$
-
   
$
50.2
 
Preliminary fair value of T2 Joint Ventures acquired
   
-
     
219.7
     
219.7
 
Equity earnings (loss)
   
10.1
     
(11.2
)
   
(1.1
)
Cash distributions (1)
   
(10.7
)
   
(0.5
)
   
(11.2
)
Cash calls for expansion projects
   
-
     
6.6
     
6.6
 
End of period
 
$
49.6
   
$
214.6
   
$
264.2
 

(1) Includes $1.1 million in distributions received from GCF and T2 Joint Ventures in excess of our share of cumulative earnings for the nine months ended September 30, 2015. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows.

The recorded value of the T2 Joint Ventures is based on preliminary fair values at the date of acquisition which results in an excess fair value of $45.1 million over the book value of our partner capital accounts. This basis difference is attributable to depreciable tangible assets and 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 - Business Acquisitions for further information regarding the preliminary fair value determinations related to the Atlas mergers.
 
Note 9 Accounts Payable and Accrued Liabilities

   
September 30, 2015 (1)
   
December 31, 2014 (1)
 
Commodities
 
$
416.5
   
$
416.7
 
Other goods and services
   
100.5
     
108.9
 
Interest
   
68.0
     
37.3
 
Compensation and benefits
   
1.0
     
1.3
 
Income and other taxes
   
42.6
     
13.6
 
Other
   
21.9
     
14.9
 
   
$
650.5
   
$
592.7
 
 

(1)
We extinguish liabilities when the creditor receives our payment and we are relieved of our obligation (which for a check generally occurs when our bank honors that check). Liabilities to creditors to whom we have issued checks that remain outstanding totaled $27.8 million and $13.3 million at September 30, 2015 and December 31, 2014 and are included above in accounts payable and accrued liabilities.
 
Note 10 — Debt Obligations

   
September 30, 2015
   
December 31, 2014
 
Current:
       
Accounts receivable securitization facility, due December 2015
 
$
135.5
   
$
182.8
 
                 
Long-term:
               
Senior secured revolving credit facility, variable rate, due October 2017 (1)
   
435.0
     
-
 
Senior unsecured notes, 5% fixed rate, due January 2018
   
1,100.0
     
-
 
Senior unsecured notes, 4% fixed rate, due November 2019
   
800.0
     
800.0
 
Senior unsecured notes, 6% fixed rate, due October 2020 (2)
   
342.1
     
-
 
Unamortized premium
   
5.2
     
-
 
Senior unsecured notes, 6% fixed rate, due February 2021
   
483.6
     
483.6
 
Unamortized discount
   
(23.0
)
   
(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, 6¾% fixed rate, due March 2024
   
600.0
     
-
 
Senior unsecured APL notes, 6% fixed rate, due October 2020 (2)(3)
   
13.1
     
-
 
Unamortized premium
   
0.2
     
-
 
Senior unsecured APL notes, 4¾% fixed rate, due November 2021 (3)
   
6.5
     
-
 
Senior unsecured APL notes, 5⅞% fixed rate, due August 2023 (3)
   
48.1
     
-
 
Unamortized premium
   
0.6
     
-
 
Total long-term debt
   
5,336.4
     
2,783.4
 
Total debt
 
$
5,471.9
   
$
2,966.2
 
Irrevocable standby letters of credit outstanding
 
$
11.2
   
$
44.1
 
 

(1) As of September 30, 2015, availability under our $1.6 billion senior secured revolving credit facility was $1,153.8 million.
(2) In May 2015, we exchanged the TRP 6⅝% Senior Notes with the same economic terms to the holders of the 2020 APL Notes (as defined below) who validly tendered such notes for exchange to us.
(3) Senior unsecured notes issued by APL entities and acquired in the Atlas mergers. While we consolidate the debt acquired in the Atlas mergers, we do not guarantee the acquired debt of APL.
 
The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the nine months ended September 30, 2015:

   
Range of Interest
Rates Incurred
   
Weighted Average
Interest Rate Incurred
 
Senior secured revolving credit facility
   
1.9% - 4.3%
 
   
2.2%
 
Accounts receivable securitization facility
   
0.9%
 
   
0.9%
 
 
Compliance with Debt Covenants

As of September 30, 2015, we were in compliance with the covenants contained in our various debt agreements.

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 some of the 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 and Targa Resources Partners Finance Corporation (collectively, the “Partnership Issuers”) issued $1.1 billion 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 after costs, which were used with borrowings under our senior secured credit facility to fund the APL Notes Tender Offers and the Change of Control Offer (each as defined below). The 5% Notes are unsecured senior obligations that have substantially the same terms and covenants as our other senior notes.

In September 2015, the Partnership Issuers issued $600 million in aggregate principal amount of 6¾% Senior Notes due 2024 (the “6¾% Notes”). The 6¾% Notes resulted in approximately $595.0 million of net proceeds after costs, which were used to reduce borrowings under our senior secured credit facility and for general partnership purposes. The 6¾% Notes are unsecured senior obligations that have substantially the same terms and covenants as our other senior notes.

April 2015 Shelf

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.

Accounts Receivable Securitization Facility

In August 2015, we reduced the maximum borrowing capacity of our accounts receivable securitization facility (the “Securitization Facility”) by $100.0 million to $200.0 million because we did not expect to fully utilize the former borrowing capacity in a lower commodity price environment. This reduction results in lower commitment fees on the unused portion of the Securitization Facility.
 
APL Merger Financing Activities

APL Senior Notes Tender Offers

In January 2015, we commenced cash tender offers for any and all of the outstanding fixed rate senior secured notes to be acquired in the APL merger, referred to as the APL Notes Tender Offers, which totaled $1.55 billion.

The results of the APL Notes 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, the supplemental indentures governing the 4¾% Senior Notes due 2021 (the “2021 APL Notes”) and the 5⅞% Senior Notes due 2023 (the “2023 APL Notes”) of TPL and Targa Pipeline Finance Corporation (formerly known as Atlas Pipeline Finance Corporation) (together, the “APL Issuers”), became operative. These supplemental indentures eliminated 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.

Not having achieved the minimum tender condition on the 6⅝% Senior Notes due 2020 of the APL Issuers (the “2020 APL Notes”), we made a change of control offer, referred to as the Change of Control Offer, for any and all of the 2020 APL Notes in advance of, and conditioned upon, the consummation of the APL merger. In March 2015, 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 Consolidated Statements of Cash Flows.

Exchange Offer and Consent Solicitation

On April 13, 2015, the “Partnership Issuers commenced an offer to exchange (the “Exchange Offer”) any and all of the outstanding 2020 APL Notes, for an equal amount of new unsecured 6⅝% Senior Notes due 2020 issued by the Partnership Issuers (the “6⅝% Notes” or the “TRP 6⅝% Notes”). On April 27, 2015, we had received tenders and consents from holders of approximately 96.3% of the total outstanding 2020 APL Notes. As a result, the minimum tender condition to the Exchange Offer and related consent solicitation was satisfied, and the APL Issuers entered into a supplemental indenture which eliminated substantially all of the restrictive covenants and certain events of default applicable to the 2020 APL Notes.
 
In May 2015, upon the closing of the Exchange Offer, the Partnership Issuers issued $342.1 million aggregate principal amount of the TRP 6⅝% Notes to holders of the 2020 APL Notes which were validly tendered for exchange. The related $5.6 million premium, resulting from acquisition date fair value accounting, will be amortized as an adjustment to interest expense over the remaining term of the TRP 6⅝% Notes. We recognized $0.5 million of costs associated with the Exchange Offer, reflected as a Loss from financing activities on our Consolidated Statements of Operations.
 
Note 11 — Partnership Units and Related Matters

Issuances of Common Units
 
As part of the Atlas merger, we issued 58,614,157 common units to former APL unitholders as consideration for the APL merger, of which 3,363,935 common units represented ATLS’s common unit ownership in APL and were issued to Targa. Targa contributed $52.4 million to us to maintain its 2% general partner interest.
 
As of January 1, 2015 we had approximately $158.4 million of capacity available under our May 2014 Equity Distribution Agreement (the “May 2014 EDA”). In May 2015, we entered into an additional Equity Distribution Agreement under the April 2015 Shelf (the “May 2015 EDA”), pursuant to which we may sell through our sales agents, at our option, up to an aggregate of $1.0 billion of our common units. During the nine months ended September 30, 2015, we issued 7,377,380 common units under our EDAs, receiving proceeds of $316.1 million (net of commissions). As of September 30, 2015, approximately $4.2 million of capacity and $835.6 million of capacity remain under the May 2014 and May 2015 EDAs. During the nine months ended September 30, 2015 Targa contributed $6.5 million to us to maintain its 2% general partner interest.
 
Subsequent Event-Preferred Units

In October 2015, under our automatic shelf registration statement filed in April 2013 and amended by a post-effective amendment filed in October 2015 (the “April 2013 Shelf”), we completed an offering of 4,400,000 Preferred Units at a price of $25.00 per unit. Pursuant to the exercise of the underwriters’ overallotment option, we sold an additional 600,000 Preferred Units at a price of $25.00 per unit. We received net proceeds after costs of approximately $121.1 million. We used the net proceeds from this offering to reduce borrowings under our senior secured credit facility and for general partnership purposes. The Preferred Units are listed on the NYSE under the symbol “NGLS PRA.”

Distributions on the Preferred Units are cumulative from the date of original issue and will be payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of our general partner. Distributions on the Preferred Units will be payable out of amounts legally available therefor from and including the date of original issue to, but not including, November 1, 2020, at a rate equal to 9.0% per annum of the stated liquidation preference. On and after November 1, 2020, distributions on the Series A Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%.

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

· senior to our common units and to each other class or series of Partnership interests or other equity securities established after the original issue date of the Preferred Units that is not expressly made senior to or pari passu with the Preferred Units as to the payment of distributions;

· pari passu with any class or series of Partnership interests or other equity securities established after the original issue date of the Preferred Units that is not expressly made senior or subordinated to the Preferred Units as to the payment of distributions;

· junior to all of our existing and future indebtedness (including (i) indebtedness outstanding under our senior secured credit facility, (ii) our 5% Notes, our 4⅛% Senior Notes due 2019, our 6⅝% Notes, our 6⅞% Senior Notes due 2021, our 6⅜% Senior Notes due 2022, our 5¼% Senior Notes due 2023, our 4¼% Senior Notes due 2023 and our 6¾% Notes and (iii) indebtedness outstanding under our Securitization Facility and other liabilities with respect to assets available to satisfy claims against us; and

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

On October 20, 2015, we announced that the board of directors of our general partner declared a prorated monthly cash distribution of $0.10 per Preferred Unit.  This cash distribution is the initial distribution payable on the Preferred Units for the period from October 15, 2015 through October 31, 2015, and will be paid November 16, 2015 on all outstanding Preferred Units to holders of record as of the close of business on October 30, 2015.

Distributions

We must distribute all of our available cash, after the preferred distribution, as defined in the Partnership Agreement, and as determined by the general partner, to common 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 nine months ended September 30, 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)
 
September 30, 2015
 
November 13, 2015
   
$
152.5
   
$
43.9
(1)   
$
4.0
   
$
200.4
   
$
0.8250
 
June 30, 2015
 
August 14, 2015
     
152.5
     
43.9
(1)    
4.0
     
200.4
     
0.8250
 
March 31, 2015
 
May 15, 2015
     
148.3
     
41.7
(1)    
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, second and third quarters of 2015. The IDR Giveback Amendment covers sixteen quarterly distribution declarations following the completion of the Atlas mergers on February 27, 2015 and will result in reallocation of IDR payments to common unitholders in 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 September 30,
   
Nine Months Ended September 30,
 
   
2015
   
2014
   
2015
   
2014
 
Net income
 
$
53.3
   
$
138.2
   
$
184.4
   
$
390.5
 
Less: Net income attributable to noncontrolling interests
   
4.8
     
9.9
     
17.3
     
30.9
 
Net income attributable to Targa Resources Partners LP
 
$
48.5
   
$
128.3
   
$
167.1
   
$
359.6
 
                                 
Net income attributable to general partner
 
$
44.9
   
$
38.6
   
$
132.0
   
$
108.2
 
Net income attributable to limited partners
   
3.6
     
89.7
     
35.1
     
251.4
 
Net income attributable to Targa Resources Partners LP
 
$
48.5
   
$
128.3
   
$
167.1
   
$
359.6
 
                                 
Weighted average units outstanding - basic
   
184.8
     
115.1
     
168.1
     
113.9
 
                                 
Net income available per limited partner unit - basic
 
$
0.02
   
$
0.78
   
$
0.21
   
$
2.21
 
                                 
Weighted average units outstanding
   
184.8
     
115.1
     
168.1
     
113.9
 
Dilutive effect of unvested stock awards
   
0.3
     
0.6
     
0.4
     
0.6
 
Weighted average units outstanding - diluted (1)
   
185.1
     
115.7
     
168.5
     
114.5
 
                                 
Net income available per limited partner unit - diluted
 
$
0.02
   
$
0.78
   
$
0.21
   
$
2.20
 

(1) For the three and nine months ended September 30, 2015, approximately 205,505 units and 187,303 units were excluded from the computation of diluted earnings per unit because the inclusion of such units would have been anti-dilutive.

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 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 and included in the acquisition date fair value of assets acquired. Derivative settlements of $20.7 million and $52.2 million related to these novated contracts were received during the three and nine months ended September 30, 2015 and were reflected as a reduction of the acquisition date fair value of the APL derivative assets acquired, with no effect on results of operations.

The "off-market" nature of these acquired derivatives can introduce a degree of ineffectiveness for accounting purposes due to an embedded financing element representing the amount that would be paid or received as of the acquisition date to settle the derivative contract. The resulting ineffectiveness can either potentially disqualify the derivative contract in its entirety for hedge accounting or alternatively affect the amount of unrealized gains or losses on qualifying derivatives that can be deferred from inclusion in periodic net income. 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. These non-qualifying hedges resulted in $1.3 million and $1.0 million of mark-to-market gains for the three and nine months ended September 30, 2015. These crude oil options expired during 2015. Additionally, for the three and nine months ended September 30, 2015, we recorded $0.4 million and $1.3 million of ineffectiveness gains related to otherwise qualifying APL derivatives, primarily natural gas swaps.
 
At September 30, 2015, the notional volumes of our commodity derivative contracts were:

Commodity
 
Instrument
 
Unit
 
2015
 
2016
 
2017
 
2018
Natural Gas
 
Swaps
 
MMBtu/d
 
 163,456
 
 79,399
 
 23,082
 
 -
Natural Gas
 
Basis Swaps
 
MMBtu/d
 
 88,099
 
 48,962
 
 18,082
 
 -
Natural Gas
 
Collars
 
MMBtu/d
 
15,400
 
 22,900
 
 22,900
 
 9,486
NGL
 
Swaps
 
Bbl/d
 
 4,268
 
 2,674
 
 1,078
 
 208
NGL
 
Options/Collars
 
Bbl/d
 
 920
 
 920
 
 920
 
 32
Condensate
 
Swaps
 
Bbl/d
 
 1,663
 
 1,082
 
 500
 
 -
Condensate
 
Options/Collars
 
Bbl/d
 
 1,605
 
 790
 
 790
 
 101

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 permit our contracting subsidiaries to net cash settle offsetting asset and liability positions with the same counterparty. 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 September 30, 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
 
$
89.0
   
$
2.1
   
$
44.4
   
$
-
 
Long-term
   
45.4
     
4.0
     
15.8
     
-
 
Total derivatives designated as hedging instruments
   
$
134.4
   
$
6.1
   
$
60.2
   
$
-
 
                                 
Derivatives not designated as hedging instruments
                                 
Commodity contracts
Current
 
$
3.3
   
$
2.2
   
$
-
   
$
5.2
 
Total derivatives not designated as hedging instruments
   
$
3.3
   
$
2.2
   
$
-
   
$
5.2
 
                                 
Total current position
   
$
92.3
   
$
4.3
   
$
44.4
   
$
5.2
 
Total long-term position
     
45.4
     
4.0
     
15.8
     
-
 
Total derivatives
   
$
137.7
   
$
8.3
   
$
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
 
September 30, 2015
 
Asset
Position
   
Liability
Position
   
Asset
Position
   
Liability
Position
 
Current position
               
Counterparties with offsetting position
 
$
87.3
   
$
4.3
   
$
83.0
   
$
-
 
Counterparties without offsetting position - assets
   
5.0
     
-
     
5.0
     
-
 
Counterparties without offsetting position - liabilities
   
-
     
-
     
-
     
-
 
     
92.3
     
4.3
     
88.0
     
-
 
Long-term position
                               
Counterparties with offsetting position
   
44.3
     
4.0
     
40.3
     
-
 
Counterparties without offsetting position - assets
   
1.1
     
-
     
1.1
     
-
 
Counterparties without offsetting position - liabilities
   
-
     
-
     
-
     
-
 
     
45.4
     
4.0
     
41.4
     
-
 
Total derivatives
                               
Counterparties with offsetting position
   
131.6
     
8.3
     
123.3
     
-
 
Counterparties without offsetting position - assets
   
6.1
     
-
     
6.1
     
-
 
Counterparties without offsetting position - liabilities
   
-
     
-
     
-
     
-
 
   
$
137.7
   
$
8.3
   
$
129.4
   
$
-
 
                                 
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 $129.4 million as of September 30, 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)
 
   
Three Months Ended
September 30,
   
Nine Months Ended
September 30,
 
Derivatives in Cash Flow
Hedging Relationships
 
2015
   
2014