UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2014

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: 001-34991

TARGA RESOURCES CORP.

(Exact name of registrant as specified in its charter)

Delaware	20-3701075
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1000 Louisiana St, Suite 4300, Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

(713) 584-1000

(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer R Accelerated filer £ Non-accelerated filer £ Smaller reporting company £

(Do not check if a smaller reporting company)

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

As of July 21, 2014, there were 42,158,448 shares of the registrant’s common stock, $0.001 par value, outstanding.

PART I—FINANCIAL INFORMATION
Item 1. Financial Statements.	4
Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013	4
Consolidated Statements of Operations for the three and six months ended June 30, 2014 and 2013	5
Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2014 and 2013	6
Consolidated Statements of Changes in Owners' Equity for the six months ended June 30, 2014 and 2013	8
Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013	9
Notes to Consolidated Financial Statements	10
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.	25
Item 3. Quantitative and Qualitative Disclosures About Market Risk.	51
Item 4. Controls and Procedures.	51
PART II—OTHER INFORMATION
Item 1. Legal Proceedings.	52
Item 1A. Risk Factors.	52
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.	52
Item 3. Defaults Upon Senior Securities.	52
Item 4. Mine Safety Disclosures.	52
Item 5. Other Information.	52
Item 6. Exhibits.	53
SIGNATURES
Signatures	55

1

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Targa Resources Corp.’s (together with its subsidiaries, other than Targa Resources Partners LP (“the Partnership”), collectively “we,” “us,” “Targa,” “TRC,” or the “Company”) reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements.” You can typically identify forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, by the use of forward-looking statements, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the risks set forth in “Part II – Other Information, Item 1A. Risk Factors.” in this Quarterly Report on Form 10-Q (“Quarterly Report”) as well as the following risks and uncertainties:

· the Partnership’s and 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 the Partnership’s transactions;

· the Partnership’s success in risk management activities, including the use of derivative instruments to hedge commodity risks;

· the level of creditworthiness of counterparties to various transactions with the Partnership;

· 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 the Partnership’s services;

· weather and other natural phenomena;

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

· the Partnership’s ability to obtain necessary licenses, permits and other approvals;

· the level and success of crude oil and natural gas drilling around the Partnership’s assets, its success in connecting natural gas supplies to its gathering and processing systems, oil supplies to its gathering systems and NGL supplies to its logistics and marketing facilities and the Partnership’s success in connecting its facilities to transportation and markets;

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

· general economic, market and business conditions; and

· the risks described elsewhere in “Part II – Other Information, Item 1A. Risk Factors.” in this Quarterly Report, our Annual Report on Form 10-K for the year ended December 31, 2013 (“Annual Report”) and our reports and registration statements filed from time to time with the United States Securities and Exchange Commission (“SEC”).

2

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in “Part II – Other Information, Item 1A. Risk Factors.” in this Quarterly Report and in our Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.

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

Bbl	Barrels (equal to 42 U.S. gallons)
Bcf	Billion cubic feet
Btu	British thermal units, a measure of heating value
BBtu	Billion British thermal units
/d	Per day
/hr	Per hour
gal	U.S. gallons
GPM	Liquid volume equivalent expressed as gallons per 1000 cu. ft. of natural gas
LPG	Liquefied petroleum gas
MBbl	Thousand barrels
MMBbl	Million barrels
MMBtu	Million British thermal units
MMcf	Million cubic feet
NGL(s)	Natural gas liquid(s)
NYMEX	New York Mercantile Exchange
GAAP	Accounting principles generally accepted in the United States of America
LIBOR	London Interbank Offer Rate
NYSE	New York Stock Exchange
Price Index Definitions
IF-NGPL MC	Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
IF-PB	Inside FERC Gas Market Report, Permian Basin
IF-WAHA	Inside FERC Gas Market Report, West Texas WAHA
NY-WTI	NYMEX, West Texas Intermediate Crude Oil
OPIS-MB	Oil Price Information Service, Mont Belvieu, Texas

3

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements.

TARGA RESOURCES CORP.

CONSOLIDATED BALANCE SHEETS

	June 30,			December 31,
	2014			2013
	(Unaudited)
	(In millions)
ASSETS
Current assets:
Cash and cash equivalents	$	75.9		$	66.7
Trade receivables, net of allowances of $1.1 million and $1.1 million		682.6			658.8
Inventories		151.7			150.7
Deferred income taxes		4.0			0.1
Assets from risk management activities		2.0			2.0
Other current assets		23.0			18.9
Total current assets		939.2			897.2
Property, plant and equipment		6,165.6			5,758.4
Accumulated depreciation		(1,541.8	)		(1,408.5	)
Property, plant and equipment, net		4,623.8			4,349.9
Intangible assets, net		622.7			653.4
Long-term assets from risk management activities		1.6			3.1
Investment in unconsolidated affiliate		52.3			55.9
Other long-term assets		88.8			89.1
Total assets	$	6,328.4		$	6,048.6
LIABILITIES AND OWNERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	806.4		$	761.8
Deferred income taxes		-			0.6
Liabilities from risk management activities		12.5			8.0
Total current liabilities		818.9			770.4
Long-term debt		3,048.2			2,989.3
Long-term liabilities from risk management activities		2.5			1.4
Deferred income taxes		142.7			135.5
Other long-term liabilities		73.1			60.7
Commitments and contingencies (see Note 15)
Owners' equity:
Targa Resources Corp. stockholders' equity:
Common stock ($0.001 par value, 300,000,000 shares authorized, 42,533,483 shares issued and 42,158,448 shares outstanding as of June 30, 2014, and 42,529,068 shares issued and 42,162,178 shares outstanding as of December 31, 2013)		-			-
Preferred stock ($0.001 par value, 100,000,000 shares authorized, no shares issued and outstanding as of June 30, 2014 and December 31, 2013)		-			-
Additional paid-in capital		149.8			151.6
Retained earnings		26.5			20.5
Accumulated other comprehensive income (loss)		(0.9	)		(0.5	)
Treasury stock, at cost (375,035 shares as of June 30, 2014 and 366,890 as of December 31, 2013)		(23.6	)		(22.8	)
Total Targa Resources Corp. stockholders' equity		151.8			148.8
Noncontrolling interests in subsidiaries		2,091.2			1,942.5
Total owners' equity		2,243.0			2,091.3
Total liabilities and owners' equity	$	6,328.4		$	6,048.6

See notes to consolidated financial statements.

4

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(Unaudited)
	(In millions, except per share amounts)
Revenues	$	2,061.9		$	1,441.6		$	4,414.8		$	2,839.4
Costs and expenses:
Product purchases		1,677.9			1,176.4			3,651.2			2,313.9
Operating expenses		106.6			96.1			210.9			182.2
Depreciation and amortization expenses		85.9			65.7			165.4			129.7
General and administrative expenses		41.6			38.4			79.5			74.6
Other operating (income) expense		(0.4	)		4.1			(1.0	)		4.2
Income from operations		150.3			60.9			308.8			134.8
Other income (expense):
Interest expense, net		(35.7	)		(32.4	)		(69.6	)		(64.5	)
Equity earnings		4.2			2.9			9.1			4.5
Gain (loss) on debt redemptions and amendments		-			(7.4	)		-			(7.4	)
Other		(0.1	)		6.5			-			6.3
Income before income taxes		118.7			30.5			248.3			73.7
Income tax (expense) benefit:
Current		(16.6	)		(7.6	)		(40.5	)		(16.8	)
Deferred		1.1			(0.4	)		2.4			(0.7	)
		(15.5	)		(8.0	)		(38.1	)		(17.5	)
Net income		103.2			22.5			210.2			56.2
Less: Net income attributable to noncontrolling interests		76.8			7.5			164.2			27.9
Net income available to common shareholders	$	26.4		$	15.0		$	46.0		$	28.3
Net income available per common share - basic	$	0.63		$	0.36		$	1.10		$	0.68
Net income available per common share - diluted	$	0.63		$	0.36		$	1.09		$	0.67
Weighted average shares outstanding - basic		42.0			41.6			42.0			41.6
Weighted average shares outstanding - diluted		42.1			42.1			42.1			42.0

See notes to consolidated financial statements.

5

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Three Months Ended June 30,
	2014									2013
	Pre-Tax			Related Income Tax			After Tax			Pre-Tax			Related Income Tax			After Tax
	(Unaudited)
	(In millions)
Net income attributable to Targa Resources Corp.							$	26.4								$	15.0
Other comprehensive income (loss) attributable to Targa Resources Corp.
Commodity hedging contracts:
Change in fair value	$	(0.8	)	$	0.3			(0.5	)	$	3.0		$	(1.1	)		1.9
Settlements reclassified to revenues		0.5			(0.2	)		0.3			(0.8	)		0.3			(0.5	)
Interest rate swaps:
Settlements reclassified to interest expense, net		0.1			(0.1	)		-			0.3			(0.1	)		0.2
Other comprehensive income (loss) attributable to Targa Resources Corp.	$	(0.2	)	$	-			(0.2	)	$	2.5		$	(0.9	)		1.6
Comprehensive income attributable to Targa Resources Corp.							$	26.2								$	16.6
Net income attributable to noncontrolling interests							$	76.8								$	7.5
Other comprehensive income (loss) attributable to noncontrolling interests
Commodity hedging contracts:
Change in fair value	$	(6.0	)	$	-			(6.0	)	$	18.2		$	-			18.2
Settlements reclassified to revenues		4.0			-			4.0			(5.1	)		-			(5.1	)
Interest rate swaps:
Settlements reclassified to interest expense, net		1.0			-			1.0			1.3			-			1.3
Other comprehensive income (loss) attributable to noncontrolling interests	$	(1.0	)	$	-			(1.0	)	$	14.4		$	-			14.4
Comprehensive income attributable to noncontrolling interests								75.8									21.9
Total comprehensive income							$	102.0								$	38.5

See notes to consolidated financial statements.

6

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Six Months Ended June 30,
	2014									2013
	Pre-Tax			Related Income Tax			After Tax			Pre-Tax			Related Income Tax			After Tax
	(Unaudited)
	(In millions)
Net income attributable to Targa Resources Corp.							$	46.0								$	28.3
Other comprehensive income (loss) attributable to Targa Resources Corp.
Commodity hedging contracts:
Change in fair value	$	(2.4	)	$	0.9			(1.5	)	$	1.9		$	(0.7	)		1.2
Settlements reclassified to revenues		1.4			(0.5	)		0.9			(1.7	)		0.7			(1.0	)
Interest rate swaps:
Settlements reclassified to interest expense, net		0.3			(0.1	)		0.2			0.5			(0.2	)		0.3
Other comprehensive income (loss) attributable to Targa Resources Corp.	$	(0.7	)	$	0.3			(0.4	)	$	0.7		$	(0.2	)		0.5
Comprehensive income attributable to Targa Resources Corp.							$	45.6								$	28.8
Net income attributable to noncontrolling interests							$	164.2								$	27.9
Other comprehensive loss attributable to noncontrolling interests
Commodity hedging contracts:
Change in fair value	$	(16.2	)	$	-			(16.2	)	$	11.8		$	-			11.8
Settlements reclassified to revenues		9.4			-			9.4			(10.8	)		-			(10.8	)
Interest rate swaps:
Settlements reclassified to interest expense, net		2.1			-			2.1			2.8			-			2.8
Other comprehensive income (loss) attributable to noncontrolling interests	$	(4.7	)	$	-			(4.7	)	$	3.8		$	-			3.8
Comprehensive income attributable to noncontrolling interests								159.5									31.7
Total comprehensive income							$	205.1								$	60.5

See notes to consolidated financial statements.

7

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY

	Common Stock					Additional Paid in			Retained Earnings (Accumulated			Accumulated Other Comprehensive			Treasury Shares					Noncontrolling
	Shares			Amount		Capital			Deficit)			Income (Loss)			Shares		Amount			Interests			Total
	(Unaudited)
	(In millions, except shares in thousands)
Balance, December 31, 2013		42,162		$	-	$	151.6		$	20.5		$	(0.5	)		367	$	(22.8	)	$	1,942.5		$	2,091.3
Compensation on equity grants		4			-		2.6			-			-			-		-			4.9			7.5
Accrual of distribution equivalent rights		-			-		-			-			-			-		-			(1.4	)		(1.4	)
Repurchase of common stock		(8	)		-		-			-			-			8		(0.8	)		-			(0.8	)
Sale of Partnership limited partner interests		-			-		-			-			-			-		-			163.0			163.0
Impact of Partnership equity transactions		-			-		8.6			-			-			-		-			(8.6	)		-
Dividends		-			-		(13.0	)		(40.0	)		-			-		-			-			(53.0	)
Distributions		-			-		-			-			-			-		-			(168.7	)		(168.7	)
Other comprehensive income (loss)		-			-		-			-			(0.4	)		-		-			(4.7	)		(5.1	)
Net income		-			-		-			46.0			-			-		-			164.2			210.2
Balance, June 30, 2014		42,158		$	-	$	149.8		$	26.5		$	(0.9	)		375	$	(23.6	)	$	2,091.2		$	2,243.0
Balance, December 31, 2012		42,295		$	-	$	184.4		$	(32.0	)	$	1.2			198	$	(9.5	)	$	1,609.3		$	1,753.4
Compensation on equity grants		36			-		3.8			-			-			-		-			3.0			6.8
Accrual of distribution equivalent rights		-			-		-			-			-			-		-			(0.7	)		(0.7	)
Sale of Partnership limited partner interests		-			-		-			-			-			-		-			260.3			260.3
Receivables from unit offerings		-			-		(32.8	)		-			-			-		-			-			(32.8	)
Impact of Partnership equity transactions		-			-		16.5			-			-			-		-			(16.5	)		-
Dividends		-			-		(40.3	)		-			-			-		-			-			(40.3	)
Distributions		-			-		-			-			-			-		-			(125.9	)		(125.9	)
Other comprehensive income (loss)		-			-		-			-			0.5			-		-			3.8			4.3
Net income		-			-		-			28.3			-			-		-			27.9			56.2
Balance, June 30, 2013		42,331		$	-	$	131.6		$	(3.7	)	$	1.7			198	$	(9.5	)	$	1,761.2		$	1,881.3

See notes to consolidated financial statements.

8

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended June 30,
	2014			2013
	(Unaudited)
Cash flows from operating activities	(In millions)
Net income	$	210.2		$	56.2
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization in interest expense		6.9			8.1
Compensation on equity grants		7.5			6.8
Depreciation and amortization expense		165.4			129.7
Accretion of asset retirement obligations		2.2			2.0
Deferred income tax expense (benefit)		(2.4	)		0.7
Equity earnings, net of distributions		-			(4.5	)
Risk management activities		(0.7	)		-
(Gain) loss on sale or disposition of assets		(1.2	)		3.8
(Gain) loss on debt redemptions and amendments		-			7.4
Changes in operating assets and liabilities:
Receivables and other assets		(31.7	)		77.6
Inventory		(18.1	)		(49.7	)
Accounts payable and other liabilities		86.4			(56.5	)
Net cash provided by operating activities		424.5			181.6
Cash flows from investing activities
Outlays for property, plant and equipment		(419.6	)		(463.4	)
Return of capital from unconsolidated affiliate		3.6			-
Other, net		2.3			(10.5	)
Net cash used in investing activities		(413.7	)		(473.9	)
Cash flows from financing activities
Partnership loan facilities:
Proceeds		950.0			1,305.0
Repayments		(850.0	)		(1,181.4	)
Partnership accounts receivable securitization facility:
Borrowings		67.8			207.7
Repayments		(113.2	)		(82.4	)
Non-Partnership loan facilities:
Proceeds		39.0			30.0
Repayments		(36.0	)		(34.0	)
Costs incurred in connection with financing arrangements		(1.7	)		(11.7	)
Distributions to owners		(168.7	)		(125.9	)
Proceeds from sale of common units of the Partnership		164.7			231.2
Dividends to common and common equivalent shareholders		(52.7	)		(39.6	)
Repurchase of common stock		(0.8	)		-
Net cash provided by (used in) financing activities		(1.6	)		298.9
Net change in cash and cash equivalents		9.2			6.6
Cash and cash equivalents, beginning of period		66.7			76.3
Cash and cash equivalents, end of period	$	75.9		$	82.9

See notes to consolidated financial statements.

9

TARGA RESOURCES CORP.

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

Targa Resources Corp. (“TRC”) is a Delaware corporation formed in October 2005. Our common stock is listed on the New York Stock Exchange under the symbol “TRGP.” In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Targa” are intended to mean our consolidated business and operations.

Note 2 — Basis of Presentation

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

The unaudited consolidated financial statements for the three and six months ended June 30, 2014 and 2013 include all adjustments, which 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 six months ended June 30, 2014 are not necessarily indicative of the results that may be expected for the full year.

One of our indirect subsidiaries is the sole general partner of Targa Resources Partners LP (“the Partnership”). Because we control the general partner of the Partnership, under GAAP, we must reflect our ownership interests in the Partnership on a consolidated basis. Accordingly, the Partnership’s financial results are included in our consolidated financial statements even though the distribution or transfer of Partnership assets is limited by the terms of the Partnership’s partnership agreement, as well as restrictive covenants in the Partnership’s lending agreements. The limited partner interests in the Partnership not owned by us are reflected in our results of operations as net income attributable to noncontrolling interests and in our balance sheet equity section as noncontrolling interests in subsidiaries. Throughout these footnotes, we make a distinction where relevant between financial results of the Partnership versus those of a standalone parent and its non-partnership subsidiaries.

As of June 30, 2014, our interests in the Partnership consist of the following:

· a 2% general partner interest, which we hold through our 100% ownership interest in the general partner of the Partnership;

· all Incentive Distribution Rights (“IDRs”); and

· 12,945,659 common units of the Partnership, representing an 11.3% limited partnership interest.

The Partnership is 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 17 for an analysis of our and the Partnership’s operations by business segment.

10

The Partnership does not have any employees. We provide operational, general and administrative and other services to the Partnership, associated with the Partnership’s existing assets and assets acquired from third parties. We perform centralized corporate functions for the Partnership, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing.

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

Reclassifications Affecting Statement of Cash Flows

In conjunction with the integration of Badlands into its financial reporting environment during 2013, the Partnership obtained further information about the acquisition date balance sheet, including the nature of the items comprising assumed Accounts payable and accrued liabilities.  The Partnership determined that certain assumed liabilities related to purchases that, under its accounting policies, are considered capital in nature. Consequently, the Partnership made certain refinements to better reflect Badlands cash flow activity on a basis similar to that used for its other operations. As a result of these refinements, certain cash flow activity was presented in its 2013 Form 10-K on a basis different than that utilized for previous quarterly reporting during 2013. In preparing this quarterly report the Partnership has made certain measurement period reclassifications to the comparative Statement of Cash Flows for the six months ended June 30, 2013 to conform to the presentation of its Form 10-K, reclassifying $18.9 million related to capital expenditures previously included in Accounts payable and other liabilities of operating activities to Outlays for property, plant and equipment in investing activities, as shown below.

	Six Months Ended June 30, 2013
Revised line items Consolidated Statement of Cash Flows	As Reported			Reclassification			Revised
Cash flows from operating activities
Changes in operating assets and liabilities:
Accounts payable and other liabilities	$	(75.4	)	$	18.9		$	(56.5	)
Net cash provided by operating activities		162.7			18.9			181.6
Cash flows from investing activities:
Changes in investing assets and liabilities:
Outlays for property, plant and equipment		(444.5	)		(18.9	)		(463.4	)
Net cash used in investing activities		(455.0	)		(18.9	)		(473.9	)

Note 3 — Significant Accounting Policies

Accounting Policy Updates/Revisions

The accounting policies that we follow are set forth in Note 3 of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2013.  There were no significant updates or revisions to these policies during the three months ended June 30, 2014.

Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant and Equipment (Topic 360), Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The amendment, required to be applied prospectively for reporting periods beginning after December 15, 2014, limits discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have, or will have, a major effect on operations and financial results.  The amendment requires expanded disclosures for discontinued operations and also requires additional disclosures regarding disposals of individually significant components that do not qualify as discontinued operations. Early adoption is permitted, but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issuance. This amendment has no impact on our current disclosures, but will in the future if we dispose of any individually significant components.

11

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

The revenue recognition standard will be effective for us starting in the first quarter of 2017. Early adoption is not permitted. We must retroactively apply the new revenue recognition standard to transactions in all prior periods presented, but will have a choice between either (1) restating each prior period presented or (2) presenting a cumulative effect adjustment in our first quarter report in 2017. We have commenced our analysis of the new standard and its impact on our revenue recognition practices.

Note 4 — Inventories

The components of inventories consisted of the following:

	June 30, 2014		December 31, 2013
Commodities	$	138.6	$	136.4
Materials and supplies		13.1		14.3
	$	151.7	$	150.7

Note 5 — Property, Plant and Equipment and Intangible Assets

	June 30, 2014									December 31, 2013
	Targa Resources Partners LP			TRC Non- Partnership			Targa Resources Corp. Consolidated			Targa Resources LP			TRC Non- Partnership			Targa Resources Corp. Consolidated			Estimated Useful Lives (In Years)
Gathering systems	$	2,332.5		$	-		$	2,332.5		$	2,230.1		$	-		$	2,230.1		5 to 20
Processing and fractionation facilities		1,824.7			6.6			1,831.3			1,598.0			6.6			1,604.6		5 to 25
Terminaling and storage facilities		863.3			-			863.3			715.2			-			715.2		5 to 25
Transportation assets		339.9			-			339.9			294.7			-			294.7		10 to 25
Other property, plant and equipment		130.8			0.2			131.0			121.3			0.2			121.5		3 to 25
Land		89.9			-			89.9			89.5			-			89.5		-
Construction in progress		577.7			-			577.7			702.8			-			702.8		-
Property, plant and equipment		6,158.8			6.8			6,165.6			5,751.6			6.8			5,758.4
Accumulated depreciation		(1,539.4	)		(2.4	)		(1,541.8	)		(1,406.2	)		(2.3	)		(1,408.5	)
Property, plant and equipment, net	$	4,619.4		$	4.4		$	4,623.8		$	4,345.4		$	4.5		$	4,349.9
Intangible assets	$	681.8		$	-		$	681.8		$	681.8		$	-		$	681.8		20
Accumulated amortization		(59.1	)		-			(59.1	)		(28.4	)		-			(28.4	)
Intangible assets, net	$	622.7		$	-		$	622.7		$	653.4		$	-		$	653.4

Intangible assets consist of customer contracts and customer relationships acquired in the Partnership’s Badlands business acquisitions. The fair value of these acquired intangible assets was determined at the date of acquisition based on the present value 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.

12

Amortization expense attributable to these intangible assets is recorded using a method that closely reflects the cash flow pattern underlying the intangible asset valuation. The estimated annual amortization expense for these intangible assets is approximately $61.4 million, $80.1 million, $88.3 million, $81.5 million and $67.8 million for each of years 2014 through 2018.

Note 6 — Asset Retirement Obligations

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

	Six Months Ended June 30, 2014
Beginning of period	$	50.9
Change in cash flow estimate		2.1
Accretion expense		2.2
End of period	$	55.2

Note 7 – Investment in Unconsolidated Affiliate

At June 30, 2014, the Partnership’s unconsolidated investment consisted of a 38.8% ownership interest in Gulf Coast Fractionators LP (“GCF”).

The following table shows the activity related to the Partnership’s investment in GCF:

	Six Months Ended
	June 30, 2014
Beginning of period	$	55.9
Equity earnings		9.1
Cash distributions (1)		(12.7	)
End of period	$	52.3

(1) Includes $3.6 million distributions received in excess of the Partnership’s share cumulative earnings that are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows.

Note 8 — Accounts Payable and Accrued Liabilities

The components of accounts payable and accrued liabilities consisted of the following:

	June 30, 2014		December 31, 2013
Commodities	$	574.4	$	520.8
Other goods and services		132.3		146.8
Interest		35.8		35.9
Compensation and benefits		37.9		40.3
Income and other taxes		20.9		10.2
Other		5.1		7.8
	$	806.4	$	761.8

13

Note 9 — Debt Obligations

	June 30, 2014			December 31, 2013
Long-term debt:
Non-Partnership obligations:
TRC Senior secured revolving credit facility, variable rate, due October 2017 (1)	$	87.0		$	84.0
Obligations of the Partnership: (2)
Senior secured revolving credit facility, variable rate, due October 2017 (3)		495.0			395.0
Senior unsecured notes, 7⅞% fixed rate, due October 2018		250.0			250.0
Senior unsecured notes, 6⅞% fixed rate, due February 2021		483.6			483.6
Unamortized discount		(26.7	)		(28.0	)
Senior unsecured notes, 6⅜% 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
Accounts receivable securitization facility, due December 2014 (4)		234.3			279.7
Total long-term debt	$	3,048.2		$	2,989.3
Irrevocable standby letters of credit:
Letters of credit outstanding under TRC Senior secured credit facility (1)	$	-		$	-
Letters of credit outstanding under the Partnership senior secured revolving credit facility (3)		94.6			86.8
	$	94.6		$	86.8

(1) As of June 30, 2014, availability under TRC’s $150 million senior secured revolving credit facility was $63.0 million.

(2) While we consolidate the debt of the Partnership in our financial statements, we do not have the obligation to make interest payments or debt payments with respect to the debt of the Partnership.

(3) As of June 30, 2014, availability under the Partnership’s $1.2 billion senior secured revolving credit facility was $610.4 million.

(4) All amounts outstanding under the Partnership’s Securitization Facility are reflected as long-term debt in our balance sheet because the Partnership has the ability and intent to fund the Securitization Facility’s borrowings on a long-term basis.

The following table shows the range of interest rates and weighted average interest rate incurred on our and the Partnership’s variable-rate debt obligations during the six months ended June 30, 2014:

	Range of Interest Rates Incurred	Weighted Average Interest Rate Incurred
TRC senior secured revolving credit facility	2.9%	2.9%
Partnership's senior secured revolving credit facility	1.9% - 4.5%	2.1%
Partnership's accounts receivable securitization facility	0.9%	0.9%

Compliance with Debt Covenants

As of June 30, 2014, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.

Note 10 — Partnership Units and Related Matters

Public Offerings of Common Units

During the six months ended June 30, 2014, the Partnership issued 3,024,901 common units under an equity distribution agreement entered into in August 2013 (the “August 2013 EDA”), receiving net proceeds of $163.0 million. We contributed $3.4million to the Partnership to maintain our 2% general partner interest.

In May 2014, the Partnership entered into an additional equity distribution agreement under its July 2013 Shelf (the “May 2014 EDA”), with Barclays Capital Inc., Citigroup Global Markets Inc., Deutsche Bank Securities Inc., Jefferies LLC, Morgan Stanley & Co. LLC, Raymond James & Associates, Inc., RBC Capital Markets, LLC, UBS Securities LLC and Wells Fargo Securities, LLC, as its sales agents, pursuant to which the Partnership may sell, at its option, up to an aggregate of $400 million of its common units. For the six months ended June 30, 2014, there were no issuances under the May 2014 EDA.

14

Subsequent Event

In July 2014, the Partnership issued 94,253 common units and 212,966 common units under the August 2013 EDA and May 2014 EDA, receiving total net proceeds of $20.9 million. We contributed $0.4 million to the Partnership to maintain our 2% general partner interest. As of July 21, 2014, approximately $385.4 million of the aggregate offering amount remained available for sale pursuant to the May 2014 EDA.

Distributions

In accordance with the Partnership Agreement, the Partnership must distribute all of its available cash, as determined by the general partner, to unitholders of record within 45 days after the end of each quarter. The following table details the distributions declared and/or paid by the Partnership for the six months ended June 30, 2014.

		Distributions
Three Months Ended	Date Paid or to be Paid	Limited Partners		General Partner						Distributions to Targa Resources Corp.		Distributions per limited partner unit
		Common		Incentive		2%		Total
(In millions, except per unit amounts)
June 30, 2014	August 14, 2014	$	89.5	$	33.7	$	2.5	$	125.7	$	46.3	$	0.7800
March 31, 2014	May 15, 2014		87.2		31.7		2.4		121.3		44.0		0.7625
December 31, 2013	February 14, 2014		84.0		29.5		2.3		115.8		41.5		0.7475

Note 11 — Common Stock and Related Matters

The following table details the dividends declared and/or paid by us for the six months ended June 30, 2014:

Three Months Ended	Date Paid or To Be Paid	Total Dividend Declared		Amount of Dividend Paid		Accrued Dividends (1)		Dividend Declared per Share of Common Stock
(In millions, except per share amounts)
June 30, 2014	August 15, 2014	$	29.2	$	29.0	$	0.2	$	0.69000
March 31, 2014	May 16, 2014		27.4		27.2		0.2		0.64750
December 31, 2013	February 18, 2014		25.6		25.5		0.1		0.60750

(1) Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.

Dividends declared are recorded as a reduction of retained earnings to the extent of retained earnings that was available at the close of the prior quarter, with any excess recorded as a reduction of additional paid-in capital.

Note 12 — Earnings per Common Share

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Net income	$	103.2	$	22.5	$	210.2	$	56.2
Less: Net income attributable to noncontrolling interests		76.8		7.5		164.2		27.9
Net income attributable to common shareholders	$	26.4	$	15.0	$	46.0	$	28.3
Weighted average shares outstanding - basic		42.0		41.6		42.0		41.6
Net income available per common share - basic	$	0.63	$	0.36	$	1.10	$	0.68
Weighted average shares outstanding		42.0		41.6		42.0		41.6
Dilutive effect of unvested stock awards		0.1		0.5		0.1		0.4
Weighted average shares outstanding - diluted		42.1		42.1		42.1		42.0
Net income available per common share - diluted	$	0.63	$	0.36	$	1.09	$	0.67

15

Note 13 — Derivative Instruments and Hedging Activities

Partnership Commodity Hedges

The primary purpose of the Partnership’s commodity risk management activities is to manage its exposure to commodity price risk and reduce volatility in its operating cash flow due to fluctuations in commodity prices. The Partnership has hedged the commodity prices associated with a portion of its expected (i) natural gas equity volumes in its Field Gathering and Processing segment and (ii) NGL and condensate equity volumes predominately in its Field Gathering and Processing segment and the LOU business unit in its Coastal Gathering and Processing segment that result from its 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. The Partnership has designated these derivative contracts as cash flow hedges for accounting purposes.

The hedges generally match the NGL product composition and the NGL and natural gas delivery points to those of the Partnership’s physical equity volumes. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon the Partnership’s 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. The Partnership’s natural gas and NGL hedges are settled using published index prices for delivery at various locations, which closely approximate the Partnership’s actual natural gas and NGL delivery points.

The Partnership hedges a portion of its condensate equity volumes using crude oil hedges that are based on the New York Mercantile Exchange (“NYMEX”) futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This necessarily exposes the Partnership to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of its underlying condensate equity volumes. Hedge ineffectiveness was immaterial for all periods presented.

At June 30, 2014, the notional volumes of the Partnership’s commodity hedges for equity volumes were:

Commodity	Instrument	Unit	2014		2015		2016
Natural Gas	Swaps	MMBtu/d		66,050		50,551		25,500
NGL	Swaps	Bbl/d		1,125		-		-
Condensate	Swaps	Bbl/d		2,450		-		-

The Partnership also enters into derivative instruments to help manage other short-term commodity-related business risks. The Partnership has not designated these derivatives as hedges, and records changes in fair value and cash settlements to revenues.

The Partnership’s derivative contracts are subject to netting arrangements that allow net cash settlement of 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.

16

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 June 30, 2014				Fair Value as of December 31, 2013
	Balance Sheet	Derivative		Derivative		Derivative		Derivative
	Location	Assets		Liabilities		Assets		Liabilities
Derivatives designated as hedging instruments
Commodity contracts	Current	$	1.2	$	11.9	$	2.0	$	7.7
	Long-term		1.6		2.5		3.1		1.4
Total derivatives designated as hedging instruments		$	2.8	$	14.4	$	5.1	$	9.1
Derivatives not designated as hedging instruments
Commodity contracts	Current	$	0.8	$	0.6	$	-	$	0.3
Total derivatives not designated as hedging instruments		$	0.8	$	0.6	$	-	$	0.3
Total current position		$	2.0	$	12.5	$	2.0	$	8.0
Total long-term position			1.6		2.5		3.1		1.4
Total derivatives		$	3.6	$	15.0	$	5.1	$	9.4

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

	Gross Presentation				Pro forma Net Presentation
	Asset		Liability		Asset		Liability
June 30, 2014	Position		Position		Position		Position
Current position
Counterparties with offsetting position	$	1.4	$	9.3	$	-	$	7.9
Counterparties without offsetting position - assets		0.6		-		0.6		-
Counterparties without offsetting position - liabilities		-		3.2		-		3.2
		2.0		12.5		0.6		11.1
Long-term position
Counterparties with offsetting position		1.3		1.2		0.1		-
Counterparties without offsetting position - assets		0.3		-		0.3		-
Counterparties without offsetting position - liabilities		-		1.3		-		1.3
		1.6		2.5		0.4		1.3
Total derivatives
Counterparties with offsetting position		2.7		10.5		0.1		7.9
Counterparties without offsetting position - assets		0.9		-		0.9		-
Counterparties without offsetting position - liabilities		-		4.5		-		4.5
	$	3.6	$	15.0	$	1.0	$	12.4
December 31, 2013
Current position
Counterparties with offsetting position	$	1.9	$	4.4	$	-	$	2.5
Counterparties without offsetting position - assets		0.1		-		0.1		-
Counterparties without offsetting position - liabilities		-		3.6		-		3.6
		2.0		8.0		0.1		6.1
Long-term position
Counterparties with offsetting position		0.7		1.2		-		0.5
Counterparties without offsetting position - assets		2.4		-		2.4		-
Counterparties without offsetting position - liabilities		-		0.2		-		0.2
		3.1		1.4		2.4		0.7
Total derivatives
Counterparties with offsetting position		2.6		5.6		-		3.0
Counterparties without offsetting position - assets		2.5		-		2.5		-
Counterparties without offsetting position - liabilities		-		3.8		-		3.8
	$	5.1	$	9.4	$	2.5	$	6.8

The fair value of the Partnership’s 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 the Partnership’s derivative instruments was a net liability of $11.4 million as of June 30, 2014. 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 Partnership’s payment obligations in connection with substantially all of these hedging transactions are secured by a first priority lien in the collateral securing its senior secured indebtedness that ranks equal in right of payment with liens granted in favor of its senior secured lenders.

17

The following tables reflect amounts recorded in 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 June 30,					Six Months Ended June 30,
Derivatives in Cash Flow Hedging Relationships	2014			2013		2014			2013
Commodity contracts	$	(6.8	)	$	21.2	$	(18.6	)	$	13.7
	$	(6.8	)	$	21.2	$	(18.6	)	$	13.7

 

	Gain (Loss) Reclassified from OCI into Income (Effective Portion)
Location of Gain (Loss)	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Interest expense, net	$	(1.1	)	$	(1.6	)	$	(2.4	)	$	(3.3	)
Revenues		(4.5	)		5.9			(10.8	)		12.5
	$	(5.6	)	$	4.3		$	(13.2	)	$	9.2

Our consolidated earnings are also affected by the Partnership’s use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings (i.e., using the “mark-to-market” method) rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. Gain (loss) recognized on commodity derivatives not designated as hedging instruments was immaterial for all periods presented.

As of June 30, 2014, the Partnership’s accumulated OCI balance includes net losses of $10.7 million related to contracts that will be settled and reclassified to revenue during the next 12 months.

The following table shows the deferred gains (losses) that are related to our consolidated accumulated OCI that will be reclassified into earnings through the end of 2016:

	June 30, 2014			December 31, 2013
Commodity hedges, before tax	$	(1.5	)	$	(0.5	)
Commodity hedges, after tax		(0.9	)		(0.3	)
Interest rate hedges, before tax		-			(0.3	)
Interest rate hedges, after tax		-			(0.2	)

See Note 14 for additional disclosures related to derivative instruments and hedging activities.

18

Note 14 — Fair Value Measurements

Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“financial instruments”). Derivative financial instruments are reported at fair value in our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost in our Consolidated Balance Sheets, with fair value measurements for these instruments provided as supplemental information.

The following are additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments.

Fair Value of Derivative Financial Instruments

The Partnership’s derivative instruments consist of financially settled commodity swaps and option contracts and fixed-price commodity contracts with certain counterparties. The Partnership determines the fair value of its derivative contracts using a discounted cash flow model for swaps and a standard option pricing-model for options, based on inputs that are readily available in public markets. The Partnership has consistently applied these valuation techniques in all periods presented and we believe the Partnership has obtained the most accurate information available for the types of derivative contracts the Partnership holds.

The fair values of the Partnership’s derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. This financial position reflects the present value, adjusted for counterparty credit risk, of the amount the Partnership expects to receive or pay in the future on its derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of $33.0 million, ignoring an adjustment for counterparty credit risk. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of $10.1 million, ignoring an adjustment for counterparty credit risk.

Fair Value of Other Financial Instruments

The contingent consideration obligation related to the Partnership’s Badlands acquisition is reported at fair value. As of June 30, 2014, the contingent consideration fully expired with no payment due. Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. As such, long-term debt is primarily the other financial instrument for which our carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows:

· Senior secured revolving credit facilities and the Partnership’s Accounts Receivable Securitization Facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and

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

Fair Value Hierarchy

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

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

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

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

19

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

	June 30, 2014
			Fair Value
	Carrying Value		Total		Level 1		Level 2		Level 3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value
Assets from commodity derivative contracts (1)	$	3.5	$	3.5	$	-	$	3.0	$	0.5
Liabilities from commodity derivative contracts (1)		14.9		14.9		-		12.4		2.5
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents		75.9		75.9		-		-		-
TRC Senior secured revolving credit facility		87.0		87.0		-		87.0		-
Partnership's Senior secured revolving credit facility		495.0		495.0		-		495.0		-
Partnership's Senior unsecured notes		2,231.9		2,369.0		-		2,369.0		-
Partnership's accounts receivable securitization facility		234.3		234.3		-		234.3		-

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

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

As of June 30, 2014, we reported certain of the Partnership’s natural gas swaps at fair value using Level 3 inputs due to such derivatives not having observable market prices for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods.

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

As of June 30, 2014, the Partnership had fifteen natural gas swaps categorized as Level 3. The significant unobservable inputs used in the fair value measurements of the Partnership’s Level 3 derivatives are the forward natural gas curves, for which a significant portion of the derivative’s term is beyond available forward pricing. The change in the fair value of Level 3 derivatives associated with a 10% change in the forward basis curve where prices are not observable is immaterial.

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

	Commodity Derivative Contracts Asset/ (Liability)
Balance, December 31, 2013	$	0.7
Settlements included in Revenue		(2.7	)
Balance, June 30, 2014	$	(2.0	)

There has been no transfer of assets or liabilities among the three levels of the fair value hierarchy during the six months ended June 30, 2014.

20

Note 15 — Commitments and Contingencies

Legal Proceedings

We are a party to various legal proceedings and/or regulatory proceedings and certain claims, suits and complaints arising in the ordinary course of business that have been filed or are pending against us. We believe all such matters are without merit or involve amounts which, if resolved unfavorably, would not have a material effect on our financial position, results of operations, or cash flows.

Contingent Consideration

Pursuant to the Membership Interest Purchase and Sale Agreement (“MIPSA”), the Partnership acquisition of Badlands was subject to a contingent payment of $50 million (the “contingent consideration”) if aggregate crude oil gathering volumes exceeded certain stipulated monthly thresholds during the period from January 2013 through June 2014. If the threshold is not attained during the contingency period, no payment is owed. Accounting standards require that the contingent consideration be recorded at fair value at the date of acquisition and revalued at subsequent reporting dates under the acquisition method of accounting. At December 31, 2012, the Partnership recorded a $15.3 million accrued liability representing the fair value of this contingent consideration, determined by a probability-based model measuring the likelihood of meeting certain volumetric measures identified in the MIPSA.

Changes in the fair value of this accrued liability are included in earnings and reported as Other income (expense) in the Consolidated Statement of Operations. As of June 30, 2013, the contingent consideration was re-estimated to be $9.1 million, a decrease of $6.2 million, reflecting at that time management’s updated assessment. The contingent period expired June 2014, with no contingent thresholds obtained.

Note 16 - Supplemental Cash Flow Information

	Six Months Ended June 30,
	2014		2013
Cash:
Interest paid, net of capitalized interest (1)	$	62.7	$	55.9
Income taxes paid, net of refunds