Tallgrass Energy, LP - FORM 10-Q

Tallgrass Energy, LP - FORM 10-Q - November 4, 2015

Attached files

Attached files

Tallgrass Energy, LP Reports

file	filename
XML - IDEA: XBRL DOCUMENT - Tallgrass Energy, LP	R9999.htm
EX-31.1 - EXHIBIT 31.1 - Tallgrass Energy, LP	tegp201593010qexhibit311.htm
EX-31.2 - EXHIBIT 31.2 - Tallgrass Energy, LP	tegp201593010qexhibit312.htm
EX-32.1 - EXHIBIT 32.1 - Tallgrass Energy, LP	tegp201593010qexhibit321.htm
EX-32.2 - EXHIBIT 32.2 - Tallgrass Energy, LP	tegp201593010qexhibit322.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)



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

For the Quarterly Period Ended September 30, 2015



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

Commission file number 001-37365

Tallgrass Energy GP, LP

(Exact name of registrant as specified in its charter)



Delaware				47-3159268
(State or other Jurisdiction of Incorporation or Organization)				(IRS Employer Identification Number)

4200 W. 115th Street, Suite 350
Leawood, Kansas				66211
(Address of Principal Executive Offices)				(Zip Code)

(913) 928-6060

(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 ý 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 ý 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. (Check one):

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

On November 4, 2015, the Registrant had 47,725,000 Class A shares and 109,504,440 Class B shares outstanding.

TALLGRASS ENERGY GP, LP

TABLE OF CONTENTS



PART 1—FINANCIAL INFORMATION	1
Item 1. Financial Statements	1
CONDENSED CONSOLIDATED BALANCE SHEETS	1
CONDENSED CONSOLIDATED STATEMENTS OF INCOME	2
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS	3
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY	4
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3. Quantitative and Qualitative Disclosures About Market Risk	44
Item 4. Controls and Procedures	45
PART II - OTHER INFORMATION	47
Item 1. Legal Proceedings	47
Item 1A. Risk Factors	47
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 3. Defaults Upon Senior Securities	47
Item 4. Mine Safety Disclosures	47
Item 5. Other Information	47
Item 6. Exhibits	47
SIGNATURES	48

Glossary of Common Industry and Measurement Terms

Bakken oil production area: Montana and North Dakota in the United States and Saskatchewan and Manitoba in Canada.

Barrel (or bbl): Forty two U.S. gallons.

Base Gas (or Cushion Gas): The volume of gas that is intended as permanent inventory in a storage reservoir to maintain adequate pressure and deliverability rates.

BBtu: One billion British Thermal Units.

Bcf: One billion cubic feet.

British Thermal Units or Btus: the amount of heat energy needed to raise the temperature of one pound of water by one degree Fahrenheit.

Condensate: A NGL with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.

Contract barrels: Barrels of crude oil that our customers have contractually agreed to ship in exchange for assurance of capacity and deliverability to delivery points.

Delivery point: the point at which product in a pipeline is delivered to the end user.

Dry gas: A gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing.

Dth: A dekatherm, which is a unit of energy equal to 10 therms or one million British thermal units.

End-user markets: The ultimate users and consumers of transported energy products.

EPA: The United States Environmental Protection Agency.

Fee Based Processing Contracts: Natural gas processing contracts that are primarily based upon a fixed fee and/or a volumetric-based fee rate, which is typically tied to reserved capacity or inlet volumes.

FERC: Federal Energy Regulatory Commission.

Firm transportation and storage services: Those services pursuant to which customers receive firm assurances regarding the availability of capacity and deliverability of natural gas on our assets up to a contracted amount at specified receipt and delivery points. Firm transportation contracts obligate our customers to pay a fixed monthly reservation charge to reserve an agreed upon amount of pipeline capacity for transportation regardless if the contracted capacity is used by the customer during each month. Firm storage contracts obligate our customers to pay a fixed monthly charge for the firm right to inject, withdraw and store a specified volume of natural gas regardless if the contracted storage capacity is actually utilized by the customer.

Fractionation: The process by which NGLs are further separated into individual, more valuable components including ethane, propane, butane, isobutane and natural gasoline.

GAAP: Generally accepted accounting principles in the United States of America.

GHGs: Greenhouse gases.

Header system: Networks of medium-to-large-diameter high pressure pipelines that connect local gathering systems to large diameter high pressure long-haul transportation pipelines.

HP: Horsepower.

Interruptible transportation and storage services: Those services pursuant to which customers receive only limited assurances regarding the availability of capacity and deliverability in transportation or storage facilities, as applicable. Under interruptible service contracts, our customers pay fees based on their actual utilization of assets for transportation and storage services. These customers are not assured capacity or service.

Keep Whole Processing Contracts: Natural gas processing contracts in which we are required to replace the Btu content of the NGLs extracted from inlet wet gas processed with purchased dry natural gas.

Line fill: The volume of oil, in barrels, in the pipeline from the origin to the destination.

Liquefied natural gas or LNG: Natural gas that has been cooled to minus 161 degrees Celsius for transportation, typically by ship. The cooling process reduces the volume of natural gas by 600 times.

Local distribution company or LDC: LDCs are involved in the delivery of natural gas to consumers within a specific geographic area.

MMBtu: One million British Thermal Units.

Mcf: One thousand cubic feet.

MMcf: One million cubic feet.

Natural gas liquids or NGLs: Those hydrocarbons in natural gas that are separated from the natural gas as liquids through the process of absorption, condensation, adsorption or other methods in natural gas processing or cycling plants. Generally such liquids consist of propane and heavier hydrocarbons and are commonly referred to as lease condensate, natural gasoline and liquefied petroleum gases. Natural gas liquids include natural gas plant liquids (primarily ethane, propane, butane and isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities).

Natural Gas Processing: The separation of natural gas into pipeline-quality natural gas and a mixed NGL stream.

Non-contract barrels (or walk-up barrels): Barrels of crude oil that our customers ship based solely on availability of capacity and deliverability with no assurance of future capacity.

No-notice service: Those services pursuant to which customers receive the right to transport or store natural gas on assets outside of the daily nomination cycle without incurring penalties.

NYMEX: New York Mercantile Exchange.

Park and loan services: Those services pursuant to which customers receive the right to store natural gas in (park), or borrow gas from (loan), our facilities on a seasonal basis.

Percent of Proceeds Processing Contracts: Natural gas processing contracts in which we process our customer’s natural gas, sell the resulting NGLs and residue gas and divide the proceeds of those sales between us and the customer. Some percent of proceeds contracts may also require our customers to pay a monthly reservation fee for processing capacity.

PHMSA: The United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration.

Play: A proven geological formation that contains commercial amounts of hydrocarbons.

Receipt point: The point where production is received by or into a gathering system or transportation pipeline.

Reservoir: A porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is characterized by a single natural pressure system.

Residue gas: The natural gas remaining after being processed or treated.

Shale gas: Natural gas produced from organic (black) shale formations.

Tailgate: The point at which processed natural gas and NGLs leave a processing facility for end-user markets.

TBtu: One trillion British Thermal Units.

Tcf: One trillion cubic feet.

Throughput: The volume of natural gas or crude oil transported or passing through a pipeline, plant, terminal or other facility during a particular period.

Uncommitted shippers (or walk-up shippers): Customers that have not signed long-term shipper contracts and have rights under the FERC tariff as to rates and capacity allocation that are different than long-term committed shippers.

Wellhead: The equipment at the surface of a well that is used to control the well’s pressure; also, the point at which the hydrocarbons and water exit the ground.

Working gas: The volume of gas in the storage reservoir that is in addition to the cushion or base gas. It may or may not be completely withdrawn during any particular withdrawal season. Conditions permitting, the total working capacity could be used more than once during any season.

Working gas storage capacity: The maximum volume of natural gas that can be cost-effectively injected into a storage facility and extracted during the normal operation of the storage facility. Effective working gas storage capacity excludes base gas and non-cycling working gas.

X/d: The applicable measurement metric per day. For example, MMcf/d means one million cubic feet per day.

PART 1—FINANCIAL INFORMATION

Item 1. Financial Statements

TALLGRASS ENERGY GP, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)



	September 30, 2015		December 31, 2014
	(in thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	19,009	$	867
Accounts receivable, net	52,926		39,768
Receivable from related party	—		73,393
Gas imbalances	862		2,442
Inventories	14,132		13,045
Derivative assets at fair value	218		—
Prepayments and other current assets	3,678		2,766
Total Current Assets	90,825		132,281
Property, plant and equipment, net	1,948,821		1,853,081
Goodwill	343,288		343,288
Intangible asset, net	98,502		104,538
Deferred tax asset	441,528		—
Deferred financing costs, net	6,114		5,528
Deferred charges and other assets	15,649		18,481
Total Assets	$	2,944,727	$	2,457,197
LIABILITIES AND PARTNERS’ EQUITY
Current Liabilities:
Accounts payable (including $8,132 and $45,534, respectively, related to VIEs)	$	19,627	$	62,329
Accounts payable to related parties	3,581		3,915
Gas imbalances	2,629		3,611
Accrued taxes	16,624		3,989
Accrued liabilities	8,924		9,384
Deferred revenue	19,786		5,468
Other current liabilities	3,664		7,872
Total Current Liabilities	74,835		96,568
Long-term debt (including $148,000 and $0, respectively, related to VIEs)	844,000		559,000
Other long-term liabilities and deferred credits	5,461		6,478
Total Long-term Liabilities	849,461		565,478
Commitments and Contingencies
Equity:
TEGP Predecessor	—		146,866
Class A Shareholders (47,725,000 and no shares outstanding, respectively)	410,906		—
Class B Shareholders (109,504,440 and no shares outstanding, respectively)	—		—
Total Partners' Capital	410,906		146,866
Noncontrolling interests	1,609,525		1,648,285
Total Equity	$	2,020,431	$	1,795,151
Total Liabilities and Equity	$	2,944,727	$	2,457,197

The accompanying notes are an integral part of these condensed consolidated financial statements.

TALLGRASS ENERGY GP, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(in thousands, except per unit amounts)
Revenues:
Sales of natural gas, NGLs, and crude oil	$	20,252		$	49,130		$	62,132		$	141,887
Natural gas transportation services	29,431			30,745			90,620			95,418
Crude oil transportation services	81,928			—			206,331			—
Processing and other revenues	6,557			10,078			26,730			24,747
Total Revenues	138,168			89,953			385,813			262,052
Operating Costs and Expenses:
Cost of sales (exclusive of depreciation and amortization shown below)	18,186			45,767			54,959			131,187
Cost of transportation services (exclusive of depreciation and amortization shown below)	14,862			3,329			39,069			13,734
Operations and maintenance	14,071			9,961			36,054			28,029
Depreciation and amortization	20,802			10,071			61,762			27,905
General and administrative	12,321			7,448			38,711			21,221
Taxes, other than income taxes	5,521			1,797			16,547			5,392
Loss on sale of assets	—			—			4,483			—
Total Operating Costs and Expenses	85,763			78,373			251,585			227,468
Operating Income	52,405			11,580			134,228			34,584
Other (Expense) Income:
Interest expense, net	(4,982		)	(1,058		)	(12,901		)	(4,492		)
Gain on remeasurement of unconsolidated investment	—			—			—			9,388
Equity in earnings of unconsolidated investment	—			—			—			717
Other income, net	502			731			1,983			2,400
Total Other (Expense) Income	(4,480		)	(327		)	(10,918		)	8,013
Net income before tax	47,925			11,253			123,310			42,597
Deferred income tax expense	(1,828		)	—			(3,600		)	—
Net income	46,097			11,253			119,710			42,597
Net income attributable to noncontrolling interests	(41,674		)	(9,623		)	(105,431		)	(35,897		)
Net income attributable to TEGP	$	4,423		$	1,630		$	14,279		$	6,700
Allocation of income for the three and nine months ended September 30, 2015:
Net income attributable to TEGP from the beginning of the period to May 11, 2015	$	—					$	7,393
Net income attributable to TEGP from May 12, 2015 to September 30, 2015	4,423						6,886
Basic net income per Class A share	$	0.09					$	0.14
Diluted net income per Class A share	$	0.09					$	0.14
Basic average number of Class A shares outstanding	47,725						47,725
Diluted average number of Class A shares outstanding	47,808						47,812

The accompanying notes are an integral part of these condensed consolidated financial statements.

TALLGRASS ENERGY GP, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)



	Nine Months Ended September 30,
	2015			2014
	(in thousands)
Cash Flows from Operating Activities:
Net income	$	119,710		$	42,597
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	64,755			28,946
Deferred tax expense	3,600			—
Gain on remeasurement of unconsolidated investment	—			(9,388		)
Noncash compensation expense	4,183			3,724
Loss on sale of assets	4,483			—
Changes in components of working capital:
Accounts receivable and other	(11,538		)	2,592
Inventories	(5,265		)	(4,661		)
Accounts payable and accrued liabilities	6,883			(14,990		)
Deferred revenue	13,995			1,459
Other operating, net	(5,359		)	(3,035		)
Net Cash Provided by Operating Activities	195,447			47,244
Cash Flows from Investing Activities:
Capital expenditures	(65,146		)	(642,216		)
Acquisition of membership interest in Pony Express	(700,000		)	(27,000		)
Acquisition of Trailblazer	—			(150,000		)
Acquisition of additional equity interests in Water Solutions	—			(7,600		)
Issuance of related party loan	—			(270,000		)
Other investing, net	(4,625		)	(2,268		)
Net Cash Used in Investing Activities	(769,771		)	(1,099,084		)
Cash Flows from Financing Activities:
Proceeds from initial public offering of Class A shares, net	1,314,741			—
Acquisition of Acquired TEP Units	(953,600		)	—
Proceeds from public offering of TEP common units, net	551,243			319,588
Distribution of Excess Proceeds to Exchange Right Holders	(334,068		)	—
Proceeds from revolver borrowings, net	285,000			433,000
Acquisition of additional Tallgrass Equity units	(171,948		)	—
Distributions to TEP unitholders	(74,843		)	(23,766		)
Contributions from noncontrolling interests	19,303			—
Tallgrass Equity distributions to noncontrolling interests	(12,969		)	—
(Distributions to) Contributions from TEGP Predecessor, net	(13,533		)	289,437
TEGP distributions to shareholders	(3,484		)	—
Contribution from Tallgrass Development, LP	—			27,488
Other financing, net	(13,376		)	6,978
Net Cash Provided by Financing Activities	592,466			1,052,725
Net Change in Cash and Cash Equivalents	18,142			885
Cash and Cash Equivalents, beginning of period	867			—
Cash and Cash Equivalents, end of period	$	19,009		$	885

Schedule of Noncash Investing and Financing Activities:
Property, plant and equipment acquired via the cash management agreement with Tallgrass Development, LP	$	120,254		$	32,479
Contributions from noncontrolling interests settled via the cash management agreement with Tallgrass Development, LP	$	43,401		$	—
Distribution to noncontrolling interests settled via the cash management agreement with Tallgrass Development, LP	$	44,142		$	—
Increase in accrual for payment of property, plant and equipment	$	—		$	2,903

The accompanying notes are an integral part of these condensed consolidated financial statements.

TALLGRASS ENERGY GP, LP

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(UNAUDITED)



	TEGP Predecessor			Partners' Capital (excluding noncontrolling interests)					Noncontrolling Interests			Total Equity
	TEGP Predecessor			Class A Shares			Class B Shares		Noncontrolling Interests			Total Equity
	(in thousands)
Balance at January 1, 2015	$	146,866		$	—		$	—	$	1,648,285		$	1,795,151
Net income for the period from January 1, 2015 to May 11, 2015	7,393			—			—		32,196			39,589
Issuance of TEP units to public, net of offering costs	63,477			—			—		487,766			551,243
Acquisition of additional 33.3% membership interest in Pony Express	(98,446		)	—			—		(601,554		)	(700,000		)
Distributions to TEGP Predecessor	(4,108		)	—			—		(9,425		)	(13,533		)
Consolidation of TEGP Predecessor assets	(115,182		)	115,182			—		—			—
Issuance of Class A shares to the public, net of offering costs	—			1,314,741			—		—			1,314,741
Acquisition of Acquired TEP Units from Tallgrass Development, LP	—			(953,600		)	—		—			(953,600		)
Distribution of excess Offering proceeds to Exchange Right Holders	—			(334,068		)	—		—			(334,068		)
Acquisition of Tallgrass Equity units from Exchange Right Holders	—			(171,948		)	—		—			(171,948		)
Deferred tax asset	—			445,128			—		—			445,128
Net income for the period from May 12, 2015 to September 30, 2015	—			6,886			—		73,235			80,121
Issuance of common units under TEP LTIP plan	—			(661		)	—		(5,901		)	(6,562		)
Distributions to TEP unitholders	—			—			—		(74,843		)	(74,843		)
Noncash compensation expense	—			195			—		7,325			7,520
Contributions from TEP's noncontrolling interest	—			—			—		110,553			110,553
Distributions to TEP's noncontrolling interest	—			—			—		(44,543		)	(44,543		)
Tallgrass Equity distributions to Exchange Right Holders	—			—			—		(12,969		)	(12,969		)
TEGP distributions to Class A shareholders	—			(3,484		)	—		—			(3,484		)
Distributions of TEP general partner and IDR distributions for periods prior to May 12, 2015 to TEP GP Members	—			(7,465		)	—		—			(7,465		)
Acquisition of noncontrolling interests	—			—			—		(600		)	(600		)
Balance at September 30, 2015	$	—		$	410,906		$	—	$	1,609,525		$	2,020,431

	TEGP Predecessor			Partners' Capital (excluding noncontrolling interests)					Noncontrolling Interests			Total Equity
	TEGP Predecessor			Class A Shares			Class B Shares		Noncontrolling Interests			Total Equity
	(in thousands)
Balance at January 1, 2014	$	150,871		$	—		$	—	$	1,158,230		$	1,309,101
Net income	6,700			—			—		35,897			42,597
Issuance of TEP units to the public, net of offering costs	45,362			—			—		274,226			319,588
Noncash compensation expense	—			—			—		7,443			7,443
Distributions to TEP unitholders	—			—			—		(23,766		)	(23,766		)
Contribution from Tallgrass Development, LP	8,344			—			—		19,144			27,488
(Distributions to) Contributions from TEP Predecessor Member, net	(21,097		)	—			—		310,534			289,437
Contributions from Noncontrolling Interest	—			—			—		5,429			5,429
Distributions to Noncontrolling Interests	—			—			—		(37		)	(37		)
Issuance of TEP general partner units to TEGP Predecessor	80			—			—		183			263
Acquisition of Trailblazer	(33,371		)	—			—		(116,629		)	(150,000		)
Acquisition of Water Solutions	—			—			—		1,400			1,400
Acquisition of 33.3% Pony Express membership interest	(10,875		)	—			—		(16,125		)	(27,000		)
Balance at September 30, 2014	$	146,014		$	—		$	—	$	1,655,929		$	1,801,943

The accompanying notes are an integral part of these condensed consolidated financial statements.

TALLGRASS ENERGY GP, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. Description of Business

Tallgrass Energy GP, LP ("TEGP" or the "Partnership") is a limited partnership that has elected to be treated as a corporation for U.S. federal income tax purposes. TEGP was formed as part of the reorganization of entities controlled by Tallgrass Equity, LLC ("Tallgrass Equity") to effect the initial public offering of Class A shares of TEGP (the "Offering"), which was completed on May 12, 2015. Prior to closing the Offering, Tallgrass Equity held a 100% membership interest in Tallgrass Energy Holdings, LLC ("Holdings"). Holdings, in turn, held a 100% limited partner interest in TEGP and a 100% membership interest in TEGP Management, LLC ("TEGP Management"), the general partner of TEGP.

In connection with the closing of the Offering on May 12, 2015, the following transactions (the “Reorganization Transactions”) occurred:


•	Tallgrass Equity distributed its membership interest in Holdings to its members, pro rata, and Holdings distributed its 100% limited partner interest in TEGP, respectively, to its members, pro rata, which are referred to as the “Exchange Right Holders”;


•	TEGP issued 47,725,000 Class A shares to the public for net proceeds of approximately $1.3 billion, including 6,225,000 Class A shares issued in connection with the underwriters' exercise of the overallotment option;


•	The existing limited partner interests in TEGP held by the Exchange Right Holders were converted into 115,729,440 Class B shares, 6,225,000 of which were automatically canceled in connection with the underwriters’ exercise of the overallotment option, resulting in the Exchange Right Holders owning 109,504,440 Class B shares;


•	Tallgrass Equity issued 41,500,000 Tallgrass Equity units to TEGP in exchange for approximately $1.1 billion in net proceeds from the issuance of TEGP’s Class A shares to the public and amended the limited liability company agreement of Tallgrass Equity to, among other things, provide that TEGP is the managing member of Tallgrass Equity;


•	TEGP used the net proceeds from the purchase of the 6,225,000 overallotment option shares to purchase Tallgrass Equity units from the Exchange Right Holders; and

•

Tallgrass Equity entered into a $150 million revolving credit facility and borrowed $150 million thereunder, using the aggregate proceeds from such borrowings together with the net proceeds from the Offering that Tallgrass Equity received from TEGP, to purchase 20,000,000 common units, representing limited partner interests in Tallgrass Energy Partners, LP ("TEP"), from Tallgrass Development, LP ("TD") at $47.68 per TEP common unit (the “Acquired TEP Units”) and pay offering expenses and other transaction costs. Tallgrass Equity distributed substantially all of the remaining proceeds (the "Excess Proceeds") to the Exchange Right Holders, retaining approximately $3 million for short term working capital needs, which will ultimately be distributed to the Exchange Right Holders to the extent not used to pay offering expenses and other transaction costs.

TEGP's sole cash-generating asset is an approximate 30.35% controlling interest in Tallgrass Equity. Tallgrass Equity's sole cash-generating assets consist of direct and indirect partnership interests in TEP, described below, that were historically owned by entities controlled by Tallgrass Equity, including TD:


•	100% of the outstanding membership interests in Tallgrass MLP GP, LLC ("TEP GP"), which owns the general partner interest in TEP as well as all of the TEP incentive distribution rights ("IDRs"). The general partner interest in TEP is represented by 834,391 general partner units, representing a 1.36% general partner interest in TEP at September 30, 2015.


•	The Acquired TEP Units, representing an approximately 32.57% limited partner interest in TEP at September 30, 2015.

The term "TEGP Predecessor" refers to TEGP, as recast to show the effects of the Reorganization Transactions, for the periods prior to completion of the Offering on May 12, 2015. "We," "us," "our" and similar terms refer to TEGP together with its consolidated subsidiaries or to TEGP Predecessor together with its consolidated subsidiaries, as the context requires, including, in both cases, Tallgrass Equity and TEP (and their respective subsidiaries).

2. Summary of Significant Accounting Policies

Basis of Presentation

These unaudited condensed consolidated financial statements and related notes for the three and nine months ended September 30, 2015 and 2014 were prepared in accordance with the accounting principles contained in the Financial Accounting Standards Board’s Accounting Standards Codification, the single source of generally accepted accounting principles in the United States of America (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2015 and 2014 include all normal, recurring adjustments and disclosures that we believe are necessary for a fair presentation of the results for the interim periods. In this report, the Financial Accounting Standards Board is referred to as the FASB and the FASB Accounting Standards Codification is referred to as the Codification or ASC.

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 ending December 31, 2015. The accompanying unaudited condensed consolidated interim financial statements should be read in conjunction with our final prospectus dated May 6, 2015 (the “Prospectus”) included in our Registration Statement on Form S-1, as amended (SEC File No. 333-202258) and filed with the United States Securities and Exchange Commission (the “SEC”) pursuant to Rule 424 on May 7, 2015.

The unaudited condensed consolidated financial statements of TEGP as of December 31, 2014 and for the three and nine months ended September 30, 2014, include historical cost basis accounts of the assets of TEGP and were prepared in contemplation of TEGP’s initial public offering of Class A shares completed on May 12, 2015 and the acquisition of an approximately 30.35% interest in Tallgrass Equity as described in Note 1 – Description of Business, which was accounted for as a transaction between entities under common control in accordance with ASC 805. Significant intra-entity items have been eliminated in the presentation. Both TEGP and TEGP Predecessor are considered entities under common control and, as such, the transfer between the entities of the assets and liabilities has been recorded by TEGP at historical cost. TEGP, as used herein, refers to the consolidated financial results and operations for TEGP Predecessor prior to the completion of the Offering and to TEGP thereafter.

Net income or loss from consolidated subsidiaries that are not wholly-owned by TEGP are attributed to TEGP and noncontrolling interests. This is done in accordance with substantive profit sharing arrangements, which generally follow the allocation of cash distributions and may not follow the respective ownership percentages held by TEGP. Concurrent with TEP's acquisition of an initial 33.3% membership interest in Tallgrass Pony Express Pipeline, LLC ("Pony Express") effective September 1, 2014, TEP, TD, and Pony Express entered into the Second Amended and Restated Limited Liability Agreement of Tallgrass Pony Express Pipeline, LLC ("the Second Amended Pony Express LLC Agreement"), which provided TEP a minimum quarterly preference payment of $16.65 million (prorated to approximately $5.4 million for the quarter ended September 30, 2014) through the quarter ended September 30, 2015. Effective March 1, 2015 with TEP's acquisition of an additional 33.3% membership interest in Pony Express, the Second Amended Pony Express LLC Agreement was further amended (as amended, "the Pony Express LLC Agreement") to increase the minimum quarterly preference payment to $36.65 million (prorated to approximately $23.5 million for the quarter ended March 31, 2015) and extend the term of the preference period through the quarter ending December 31, 2015. The Pony Express LLC Agreement provides that the net income or loss of Pony Express be allocated, to the extent possible, consistent with the allocation of Pony Express cash distributions. Under the terms of the Pony Express LLC Agreement, Pony Express distributions and net income for periods beginning after December 31, 2015 will be attributed to TEP and its noncontrolling interests in accordance with the respective ownership interests.

A variable interest entity ("VIE") is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has a variable interest that could be significant to the VIE and the power to direct the activities that most significantly impact the entity’s economic performance. We have presented separately in our condensed consolidated balance sheets, to the extent material, the assets of our consolidated VIEs that can only be used to settle specific obligations of the consolidated VIEs, and the liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit. Tallgrass Equity and Pony Express are considered to be VIEs under the applicable authoritative guidance. Based on a qualitative analysis in accordance with the applicable authoritative guidance, we have determined that we have the power to direct matters that most significantly impact the activities of Tallgrass Equity and Pony Express and have the right to receive benefits of Tallgrass Equity and Pony Express that could potentially be significant to the respective entities. We have consolidated Tallgrass Equity as we are the primary beneficiary. We also consolidate Pony Express through our indirect investment in TEP, as TEP is the primary beneficiary of Pony Express. For additional information see Note 3 – Variable Interest Entities.

Use of Estimates

Certain amounts included in or affecting these condensed consolidated financial statements and related disclosures must be estimated, requiring management to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts reported for assets, liabilities, revenues, and expenses during the reporting period, and the disclosure of contingent assets and liabilities at the date of the financial statements. Management evaluates these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods it considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from these estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

Cash and Cash Equivalents

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Net equity contributions and distributions included in the condensed consolidated statements of cash flows represent transfers of cash as a result of TD’s centralized cash management systems prior to April 1, 2014 for Trailblazer Pipeline Company LLC ("Trailblazer") and September 1, 2014 for Pony Express, under which cash balances were swept periodically and recorded as loans from the subsidiaries to TD. These loans were then periodically recorded as equity distributions. Pony Express participates in a cash management agreement with TD, which holds a 33.3% common membership interest in Pony Express, under which cash balances are swept daily and recorded as loans from Pony Express to TD.

All payable and receivable balances between TEGP and TD are cash settled with the exception of certain balances payable from Pony Express to TD, which have been settled against the receivable from TD via the Pony Express cash management agreement discussed in the prior paragraph.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are carried at their estimated collectible amounts. We make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and adjustments are recorded as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. Our allowance for doubtful accounts totaled $0.7 million and $0.5 million at September 30, 2015 and December 31, 2014.

Inventories

Inventories primarily consist of gas in underground storage, materials and supplies, natural gas liquids and crude oil. Gas in underground storage, sometimes referred to as working gas, and natural gas liquids are recorded at the lower of historical cost or market using the average cost method. As discussed further under "Revenue Recognition" below, a loss allowance is factored into the crude oil tariffs to offset losses in transit. As crude oil is transported, we earn oil for our services as pipeline allowance oil, which we can then sell. As pipeline allowance oil is accumulated, it is recorded as inventory at the lower of historical cost or market using the average cost method. Materials and supplies are valued at weighted average cost and periodically reviewed for physical deterioration and obsolescence. For additional information, see "Gas in Underground Storage" below.

Accounting for Regulatory Activities

Regulated activities are accounted for in accordance with the "Regulated Operations" Topic of the Codification. This Topic prescribes the circumstances in which the application of GAAP is affected by the economic effects of regulation. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. We had recorded regulatory assets of approximately $1.2 million and $1.4 million included in "Deferred charges and other assets" in the condensed consolidated balance sheets at September 30, 2015 and December 31, 2014, respectively. Regulatory assets at September 30, 2015 and December 31, 2014 were primarily attributable to costs associated with Trailblazer’s 2013 Rate Case Filing as more fully described in Note 13 – Regulatory Matters.

Property, Plant and Equipment

Property, plant and equipment is stated at historical cost, which for constructed plants includes indirect costs such as payroll taxes, other employee benefits, allowance for funds used during construction for regulated assets and other costs directly related to the projects. Expenditures that increase capacities, improve efficiencies or extend useful lives are capitalized and depreciated over the remaining useful life of the asset or major asset component. We also capitalize certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs.

Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of the regulated depreciable utility property, plant and equipment, plus the cost of removal less salvage value and any gain or loss recognized, is recorded in accumulated depreciation with no effect on current period earnings. Gains or losses are recognized upon retirement of non-regulated or regulated property, plant and equipment constituting an operating unit or system, and land, when sold or abandoned and costs of removal or salvage are expensed when incurred.

Intangible Assets

We account for intangible assets in accordance with ASC 805, which established that an intangible asset is identifiable if it meets either the separability criterion or the contractual-legal criterion. Further, in accordance with ASC 805, contract-based intangible assets represent the value of rights that arise from contractual arrangements. Use rights such as drilling, water, air, timber cutting, and route authorities are an example of contract-based intangible assets. Intangible assets arose at Pony Express from the acquisition of rights associated with the ability and regulatory permissions to convert a section of the Tallgrass Interstate Gas Transmission, LLC ("TIGT") natural gas pipeline, which was subsequently purchased by Pony Express, to crude oil and includes the operational and financial benefits that accrue due to those rights and the ability to make that asset more valuable ("the Pony Express oil conversion use rights"). These intangible assets are amortized on a straight-line basis over a period of 35 years, the period of expected future benefit. Intangible assets arose at BNN Redtail, LLC ("Redtail") as a result of a significant customer contract with favorable market terms which was acquired as part of the BNN Water Solutions, LLC ("Water Solutions") transaction discussed in Note 4 – Acquisitions. This intangible asset is amortized on a straight-line basis over a period of 1.6 years, the remaining term of the contract at the time of acquisition.

Impairment of Long-Lived Assets

We review our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss results when the estimated undiscounted future net cash flows expected to result from the asset’s use and its eventual disposition are less than its carrying amount. We assess our long-lived assets for impairment in accordance with the relevant Codification guidance. A long-lived asset is tested for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair value.

Examples of long-lived asset impairment indicators include:


•	a significant decrease in the market value of a long-lived asset or group;


•	a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition;


•	a significant adverse change in legal factors or in the business climate could affect the value of long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process;


•	an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the long-lived asset or asset group;


•	a current period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and


•	a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

When an impairment indicator is present, we first assesses the recoverability of the long-lived assets by comparing the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset to the carrying amount of the asset. If the carrying amount is higher than the undiscounted future cash flows, the fair value of the assets is assessed using a discounted cash flow analysis and used to determine the amount of impairment, if any, to be recognized.

Gas in Underground Storage

Gas in underground storage represents the cost of base gas, which refers to the volumes necessary to maintain pressure and deliverability requirements in our storage facilities. We record base gas as a component of property, plant and equipment.

We maintain working gas in our underground storage facilities on behalf of certain third parties. We receive a fee for our storage services but do not reflect the value of third party gas in the accompanying condensed consolidated financial statements. We occasionally acquire volumes of working gas for our own account. These volumes of working gas are recorded as natural gas inventory at the lower of cost or market.

Depreciation and Amortization - Regulated Assets

For our regulated assets at TIGT and Trailblazer, we have elected to compute depreciation using a composite method employed by applying a single, FERC approved depreciation rate to a group of assets with similar economic characteristics. This composite method of depreciation approximates a straight-line method of depreciation. The annualized rate of depreciation ranges from 0.70% to 12.00% for the various classes of depreciable, regulated assets.

Depreciation and Amortization - Non-regulated Assets

For non-regulated assets, we have elected to use the straight-line method of depreciation. The useful lives for the various classes of non-regulated depreciable assets are as follows:



	Range of Useful Lives
	(in years)
Crude oil pipelines	35
Processing & Treating	30
Natural gas pipelines ⁽¹⁾	10
General & Other	3-13 1/3


⁽¹⁾	Includes the Replacement Gas Facilities as discussed in Note 5 – Related Party Transactions and Note 13 – Regulatory Matters.

Gas Imbalances

Gas imbalances receivable and payable represent the difference between customer nominations and actual gas receipts from, and gas deliveries to, interconnecting pipelines under various operational balancing and imbalance agreements. Gas imbalances are either made up in-kind or settled in cash, subject to the terms and valuations of the various agreements. Imbalances are valued at applicable average market index prices.

Deferred Financing Costs

Costs incurred in connection with the issuance of long-term debt are deferred and amortized over the related financing period using the effective interest method.

Goodwill

We evaluate goodwill for impairment on an annual basis and whenever events or changes in circumstances necessitate an evaluation for impairment. Examples of such facts and circumstances include changes in the magnitude of the excess of the fair value over the carrying amount in the last valuation or changes in the business environment. Our annual impairment testing date is August 31st. We evaluate goodwill for impairment at the reporting unit level, which is an operating segment as defined in the segment reporting guidance of the Codification, using either the qualitative assessment option or the two-step test approach depending on facts and circumstances of the reporting unit. If we, after performing the qualitative assessment, determine it is "more likely than not" that the fair value of a reporting unit is greater than its carrying amount, the two-step impairment test is unnecessary. When goodwill is evaluated for impairment using the two-step test, the carrying amount of the reporting unit is compared to its fair value in Step 1 and if the fair value exceeds the carrying amount, Step 2 is unnecessary. If the carrying amount exceeds the reporting unit’s fair value, this could indicate potential impairment and Step 2 of the goodwill evaluation process is required to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any. When Step 2 is necessary, the fair value of individual assets and liabilities is determined using valuations, or other observable sources of fair value, as appropriate. If the carrying amount of goodwill exceeds its implied fair value, the excess is recognized as an impairment loss.

We did not elect to apply the qualitative assessment option during our 2015 annual goodwill impairment testing, instead we proceeded directly to the two-step quantitative test. In Step 1 of the two-step quantitative test, we compared the fair value of each reporting unit with its respective book value, including goodwill, by using an income approach based on a discounted cash flow analysis. For the purpose of goodwill impairment testing, goodwill was allocated to our reporting units based on the enterprise value of each reporting unit at the date of acquisition. The fair value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and included a sensitivity analysis of the impact of changes in various assumptions. This approach required us to make long-term forecasts of future operating results and various other assumptions and estimates, the most significant of which are gross margin, operating expenses, general and administrative expenses, long-term growth rates and the weighted average cost of capital. The fair value of the reporting units was determined using significant unobservable inputs, considered Level 3 under the fair value hierarchy in the Codification. For each reporting unit, the results of the Step 1 impairment analysis indicated no potential impairment as the fair value of the reporting units was greater than their respective book values. As a result, in accordance with the Codification guidance, Step 2 of the impairment analysis was not necessary as part of the annual impairment analysis in 2015. Unpredictable events or deteriorating market or operating conditions could result in a future change to the discounted cash flow models and cause impairments in the future. We continue to monitor potential impairment indicators to determine if a triggering event occurs and will perform additional goodwill impairment analyses as necessary.

Investment in Unconsolidated Affiliates

We use the equity method to account for investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and for investments in less than 20% owned affiliates where we have the ability to exercise significant influence.

We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in value, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. We assess the fair value of our investments in unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. The difference between the carrying amount of the unconsolidated affiliates and their estimated fair value is recognized as an impairment loss when the loss in value is deemed to be other-than-temporary.

Our investment in Grasslands Water Services I, LLC ("GWSI"), which owns a water transportation pipeline, was initially recorded under the equity method of accounting as we had the ability to exercise significant influence, but not control, over this investment. There was $0.7 million equity in earnings recognized for the nine months ended September 30, 2014. There were no equity in earnings recognized for the three months ended September 30, 2014 and the three and nine months ended September 30, 2015. As discussed in Note 4 – Acquisitions, during the year ended December 31, 2014, TEGP acquired a controlling interest in GWSI, which was subsequently renamed BNN Redtail, LLC ("Redtail"), and consolidated its investment in Redtail as of May 13, 2014 accordingly.

Revenue Recognition

We recognize revenues as services are rendered or goods are sold to a purchaser at a fixed and determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. We provide various types of natural gas storage and transportation services and crude oil transportation services to our customers in which the commodity remains the property of these customers at all times.

Natural gas liquids sales occur in the Processing & Logistics segment and consist of the sale of outputs from our processing plants and the marketing of natural gas liquids that are delivered by our suppliers under either fee-based arrangements or percent-of-proceeds arrangements. Under these arrangements, we treat and process the natural gas delivered by our suppliers, and then sell the resulting NGLs and condensate based on published index market prices. We remit to the producers an agreed-upon percentage of the actual proceeds that we receive from our sales of the NGLs and condensate. We keep the difference between the proceeds received and the amount remitted back to the producer. We generally report gross revenues in the condensed consolidated statements of income, as we typically act as the principal in these transactions, take custody of the product, and incur the risks and rewards of ownership. Processing and other revenues primarily represent fees for processing, treating and fractionation of natural gas and NGLs earned under fee-based arrangements and revenue from water services earned in the Processing & Logistics segment.

Natural gas sales occur in both the Natural Gas Transportation & Logistics segment and in the Processing & Logistics segment. In the Natural Gas Transportation & Logistics segment, transportation services revenue is recognized when a portion of the natural gas transported by customers is collected as a contractual fee to compensate us for fuel consumed by pipeline and storage operations. We take title and record revenue at market prices when the volumes included in the contractual fee are delivered from the customer and injected into our storage facility. When the excess volumes are eventually sold we record natural gas sales revenue at the contractual sales price and cost of sales at average cost. In addition, when operational conditions allow, we occasionally sell "base gas," which refers to the minimum volume of natural gas required in order to operate the storage facility. In the Processing & Logistics segment, we purchase natural gas primarily for use in our operations and for meeting contractual requirements to deliver natural gas to certain customers. In addition, some of our contractual arrangements allow us to keep a portion of the processed natural gas as compensation for processing services. We generate revenue by selling the volumes of natural gas received or purchased that exceed our business needs.

Natural gas transportation and storage services occur in the Natural Gas Transportation & Logistics segment. In many cases (generally described as "firm service"), the customer pays a two-part rate that includes (i) a fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fee-based component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/withdrawn from our storage facilities. In other cases (generally described as "interruptible service"), there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements. In addition to "firm" and "interruptible" transportation services, we also provide natural gas park and loan services to assist customers in managing short-term gas surpluses or deficits. Revenues are recognized as services are provided, based on the terms negotiated under these contracts.

Crude oil transportation services occur in the Crude Oil Transportation & Logistics segment. We provide various types of crude oil transportation services to our customers and, other than pipeline allowance oil, do not take title to the crude oil and do not incur the risks and rewards of ownership. In many cases the customer has committed to ship a fixed quantity of oil barrels per month. For barrels physically received by us and delivered to the customers’ agreed upon destination point, revenue is recognized in the period the service is provided. Shipper deficiencies, or barrels committed by the customer to be transported in a month but not physically received by us for transport or delivered to the customers’ agreed upon destination point, are charged at the committed tariff rate per barrel and recorded as a deferred liability until the barrels are physically transported and delivered. In the case of non-committed shippers, revenue is recognized in the same manner utilized for the barrels physically transported and delivered. A loss allowance is factored into the crude oil tariffs to offset losses in transit. As crude oil is transported, we earn oil for our services as pipeline allowance oil. Any pipeline allowance oil that remains after replacing losses in transit can be sold. We take title and record revenue at market prices when the volumes included in the pipeline loss allowance are delivered from the customer. When pipeline loss allowance oil is eventually sold we record revenue at the contractual sales price and cost of sales at average cost as discussed in "Inventories" above. During the three and nine months ended September 30, 2015, we recognized revenue of $1.3 million and $2.5 million on the sale of pipeline allowance oil, which is included in "Sales of natural gas, NGLs, and crude oil" in the condensed consolidated statements of income.

Commitments and Contingencies

We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss.

Environmental Costs

We expense or capitalize, as appropriate, environmental expenditures that relate to current operations. We expense amounts that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation. We do not discount environmental liabilities to a net present value, and record environmental liabilities when environmental assessments and/or remedial efforts are probable and costs can be reasonably estimated. Recording of these accruals coincides with the completion of a feasibility study or a commitment to a formal plan of action. Estimates of environmental liabilities are based on currently available facts and presently enacted laws and regulations taking into consideration the likely effects of other factors including our prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual cost or new information.

Fair Value

Fair value, as defined in the Codification, is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. We apply the fair value measurement guidance to financial assets and liabilities in determining the fair value of derivative assets and liabilities, and to nonfinancial assets and liabilities upon the acquisition of a business or in conjunction with the measurement of an impairment loss on an asset group or goodwill under the accounting guidance for the impairment of long-lived assets or goodwill.

The fair value measurement accounting guidance requires that we make assumptions that market participants would use in pricing an asset or liability based on the best information available. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk of the reporting entity (for liabilities) and of the counterparty (for assets). The fair value measurement guidance prohibits the inclusion of transaction costs and any adjustments for blockage factors in determining the instruments’ fair value. The principal or most advantageous market should be considered from the perspective of the reporting entity.

Fair value, where available, is based on observable market prices. Where observable market prices or inputs are not available, different valuation models and techniques are applied. These models and techniques attempt to maximize the use of observable inputs and minimize the use of unobservable inputs. The process involves varying levels of management judgment, the degree of which is dependent on the price transparency of the instruments or market and the instruments’ complexity.

To increase consistency and enhance disclosure of fair value, the Codification creates a fair value hierarchy to prioritize the inputs used to measure fair value into three categories. An asset or liability’s level within the fair value hierarchy is based on the lowest level of input significant to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest. The three levels are defined as follows:


•	Level 1 Inputs-quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;


•	Level 2 Inputs-inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and


•	Level 3 Inputs-unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data).

Any transfers between levels within the fair value hierarchy are recognized at the end of the reporting period.

For information regarding financial instruments measured at fair value on a recurring basis, see Note 8 – Risk Management. For information regarding the fair value of financial instruments not measured at fair value in the condensed consolidated balance sheets, see Note 9 – Long-term Debt.

Risk Management Activities

We utilize energy derivatives for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas. We record derivative contracts at their estimated fair values as of each reporting date. For more information on our risk management activities, see Note 8 – Risk Management.

Equity-Based Compensation

Equity-based compensation grants are measured at their grant date fair value and related compensation cost is recognized over the vesting period of the grant. Compensation cost for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award. A portion of the expense recognized relating to equity-based compensation grants is charged to TD.

Income Taxes

Prior to the completion of the Offering on May 12, 2015, TEGP Predecessor was comprised solely of limited liability companies that elected to be treated as partnerships for income tax purposes. Accordingly, no provision for federal or state income taxes was recorded in the financial statements of TEGP Predecessor and the tax effects of our activities accrued to their respective partners and members for periods prior May 12, 2015. Subsequent to May 12, 2015, TEGP's consolidated subsidiaries consist primarily of entities that have elected to be treated as partnerships for income tax purposes. On September 14, 2015, TEGP, through its membership interest in Pony Express, formed a new C corporation, Tallgrass Colorado Pipeline, Inc. ("Tallgrass Colorado"), which is 99.8% owned by Pony Express. The remaining 0.2% interest in Tallgrass Colorado is held by direct and indirect wholly owned subsidiaries of TEP. Tallgrass Colorado was formed for the purpose of the potential construction of a lateral pipeline that would interconnect with the Pony Express System's existing lateral in Northeast Colorado and has not yet commenced operations or generated any income.

Although TEGP is organized as a limited partnership, we have elected to be treated as a corporation for U.S. federal income tax purposes and are therefore subject to both U.S. federal and state income taxes for periods beginning May 12, 2015. We recognized a deferred tax asset of $445.1 million as a result of the Reorganization Transactions in connection with the Offering, $3.6 million of which was recognized as deferred income tax expense during the period from May 12, 2015 to September 30, 2015.

We estimate an annual effective income tax rate based on projected results for the year and apply this rate to income before taxes to calculate income tax expense. All earnings from TEGP's consolidated subsidiaries are included in our net income, however we are not required to record income tax expense with respect to the portion of our earnings allocated to noncontrolling interests, which reduces our effective tax rate.

Our effective income tax rate for the period from May 12, 2015 to September 30, 2015 was 4.30%. We are projecting a tax loss for both U.S. Federal and State income taxes for the year ended December 31, 2015. As a result, there is no current provision for income taxes for the three and nine months ended September 30, 2015.

Pursuant to the applicable guidance related to accounting for uncertainty in income taxes, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the tax position and also the past administrative practices and precedents of the taxing authority. As of three and nine months ended September 30, 2015, we had not recognized any material amounts in connection with uncertainty in income taxes.

Accounting Pronouncements Issued But Not Yet Effective

Accounting Standards Update ("ASU") No. 2014-09, "Revenue from Contracts with Customers (Topic 606)"

In May 2014, the Financial Accounting Standards Board ("FASB") issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, entities must apply a five step process to (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract.

The amendments in ASU 2014-09 are effective for public entities for annual reporting periods beginning after December 15, 2017, and for interim periods within that reporting period. Early application is permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating the impact of ASU 2014-09.

ASU No. 2014-12, "Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period"

In June 2014, the FASB issued ASU No. 2014-12, Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. ASU 2014-12 provides explicit guidance on accounting for share-based payments requiring a specific performance target to be achieved in order for employees to become eligible to vest in the awards when that performance target may be achieved after the requisite service period for the award. The ASU requires that such performance targets be treated as a performance condition, and should not be reflected in the estimate of the grant-date fair value of the award. Instead, compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved.

ASU 2014-12 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption is permitted. The adoption of ASU 2014-12 is not expected to have a material impact on our financial position and results of operations.

ASU No. 2015-02, "Consolidation (Topic 810): Amendments to the Consolidation Analysis"

In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810) - Amendments to the Consolidation Analysis. ASU 2015-02 will change the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. ASU 2015-02 will modify the evaluation of whether limited partnerships and other similar legal entities are considered VIEs or voting interest entities, eliminate the presumption that a general partner should consolidate a limited partnership, and change certain aspects of the consolidation analysis for reporting entities that are involved with VIEs, particularly for those with fee arrangements and related party relationships.

The amendments in ASU 2015-02 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early application is permitted, including adoption in an interim period. We are currently evaluating the impact of ASU 2015-02.

ASU No. 2015-11, "Inventory (Topic 330): Simplifying the Measurement of Inventory"

In July 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330), Simplifying the Measurement of Inventory. ASU 2015-11 establishes a "lower of cost and net realizable value" model for the measurement of most inventory balances. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation.

The amendments in ASU 2015-11 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2016. Early adoption is permitted. We are currently evaluating the impact of ASU 2015-11.

3. Variable Interest Entities

TEGP, as the managing member of Tallgrass Equity, has voting rights disproportionate to its ownership interest. As a result, we have determined that Tallgrass Equity is a VIE of which we are the primary beneficiary and we consolidate Tallgrass Equity accordingly. We have not provided any additional financial support to Tallgrass Equity other than our initial capital contribution and have no contractual commitments or obligations to provide additional financial support.

We also consolidate Pony Express through our indirect ownership of TEP. TEP does not have the obligation to absorb losses from Pony Express during the preference period as a result of the minimum quarterly preference payments as discussed in Note 4 – Acquisitions. In addition, for the period from our acquisition of the initial 33.3% membership interest effective September 1, 2014 to our acquisition of an additional 33.3% membership interest effective March 1, 2015, TEP, as the managing member of Pony Express, had voting rights disproportionate to its ownership interest. As a result, we determined that Pony Express is a VIE of which TEP is the primary beneficiary and consolidated Pony Express accordingly. TEP has not provided any additional financial support to Pony Express other than its initial capital contribution of $570 million and has no contractual commitments or obligations to provide additional financial support. In the event that the costs of construction of the Pony Express System's mainline and its lateral in Northeast Colorado exceed the $270 million retained by Pony Express as discussed in Note 4 – Acquisitions, TD is obligated to fund the remaining costs. As of September 30, 2015, the costs to complete construction have exceeded the amount retained, and as such TD will continue to fund any remaining costs associated with construction of the mainline and lateral in Northeast Colorado. Although TEP has no obligation to provide further financial support to Pony Express, it is expected that future capital projects would be funded by TEP and TD on a pro rata basis in accordance with the Pony Express LLC Agreement.

The carrying amounts and classifications of the Tallgrass Equity consolidated assets and liabilities, including the assets and liabilities of Pony Express, included in our condensed consolidated balance sheets at September 30, 2015 and December 31, 2014 are as follows:



	September 30, 2015		December 31, 2014
	(in thousands)
Current assets	$	90,824	$	132,281
Noncurrent assets	2,412,376		2,324,916
Total assets	$	2,503,200	$	2,457,197
Current liabilities	$	74,835	$	96,568
Noncurrent liabilities	849,461		565,478
Total liabilities	$	924,296	$	662,046

4. Acquisitions

TEP Acquisition of Trailblazer

On April 1, 2014, TEP closed the acquisition of Trailblazer from a wholly owned subsidiary of TD for total consideration valued at approximately $164 million, consisting of $150 million in cash and the issuance of 385,140 TEP common units (valued at approximately $14 million based on the March 31, 2014 closing price of TEP’s common units). On that same date, the general partner contributed additional capital in the amount of approximately $263,000 in exchange for the issuance of 7,860 TEP general partner units in order to maintain its 2% general partner interest. The acquisition of Trailblazer represents a change in reporting entity and a transaction between entities under common control. The excess purchase price over the net book value of Trailblazer's assets and liabilities was accounted for as a deemed distribution to TEP GP.

TEP Acquisitions of 66.7% of Pony Express

Effective September 1, 2014, TEP acquired a controlling 33.3% membership interest in Pony Express for total consideration of approximately $600 million. At closing, Pony Express, TD, and TEP entered into the Second Amended Pony Express LLC Agreement, which set forth the relative rights of TD and TEP as the owners of Pony Express. Of the total consideration of $600 million, TEP directly paid TD $30 million, consisting of $27 million in cash and 70,340 TEP common units with an aggregate fair value of approximately $3 million, in exchange for the transfer by TD to TEP of a 1.9585% membership interest in Pony Express (computed before giving effect to the issuance of the new membership interest by Pony Express to TEP). TEP also contributed cash of $570 million to Pony Express in exchange for a newly issued membership interest which, when combined with the membership interest transferred from TD and the parties' entry at closing into the Second Amended Pony Express LLC Agreement, constituted TEP's 33.3% membership interest in Pony Express, which represented 100% of the preferred membership units issued by Pony Express. Of the $570 million cash consideration received by Pony Express, $300 million was immediately distributed to TD at closing and $270 million was retained by Pony Express to fund the estimated remaining costs of construction for the Pony Express System and the lateral in Northeast Colorado. The $270 million cash balance was subsequently swept to TD under a cash management agreement between Pony Express and TD and was recorded as a related party loan which bears interest at TD's incremental borrowing rate. There was no remaining balance outstanding on the related party loan at September 30, 2015.

The terms of TEP's first acquisition of a 33.3% membership interest in Pony Express provided TEP a minimum quarterly preference payment of $16.65 million through the quarter ended September 30, 2015 (prorated to approximately $5.4 million for the quarter ended September 30, 2014) with distributions thereafter shared in accordance with the terms of the Second Amended Pony Express LLC Agreement. At the effective date of that transaction, TEP determined that Pony Express was a VIE of which TEP was the primary beneficiary, and consolidated Pony Express accordingly. For additional discussion and disclosure, see Note 3 – Variable Interest Entities. The acquisition of the initial 33.3% membership interest in Pony Express represented a transaction between entities under common control and a change in reporting entity.

Effective March 1, 2015, TEP acquired an additional 33.3% membership interest in Pony Express for cash consideration of $700 million. At closing, Pony Express, TD, and TEP entered into the Pony Express LLC Agreement, which sets forth the relative rights of TD and TEP as the owners of Pony Express. The terms of the transaction increased the minimum quarterly preference payment provided to TEP to $36.65 million through the quarter ending December 31, 2015 (prorated to approximately $23.5 million for the quarter ended March 31, 2015) with distributions thereafter shared in accordance with the terms of the Pony Express LLC Agreement.

Upon the effective date of the second acquisition, TEP reevaluated its VIE assessment and determined that Pony Express continues to be considered a VIE of which TEP is the primary beneficiary. The acquisition of the additional 33.3% membership interest in Pony Express represents a transaction between entities under common control and an acquisition of noncontrolling interests. As a result, financial information for periods prior to the transaction have not been recast to reflect the additional 33.3% membership interest.

Formation of BNN Water Solutions, LLC

On November 26, 2013, TEP, through its wholly-owned subsidiary Tallgrass Energy Investments, LLC ("TEI"), entered into a joint venture agreement with BNN Energy LLC ("BNN") to form Grasslands Water Services I, LLC ("GWSI"), which subsequently built and began operating an intrastate water pipeline in Colorado. TEP accounted for its 50% equity interest in GWSI as an equity method investment. On May 13, 2014, TEI entered into a contribution agreement with BNN and several other parties to form a new entity known as Water Solutions. Under the terms of the contribution agreement, TEI agreed to contribute its existing 50% interest in GWSI, along with $7.6 million cash, in exchange for an 80% membership interest in Water Solutions. As part of the transaction, GWSI was renamed BNN Redtail, LLC ("Redtail"), became a subsidiary of Water Solutions, and issued preferred equity interests to TEI. Among the assets contributed by BNN and the other parties to the transaction were the other 50% interest in Redtail and a 100% equity interest in Alpha Reclaim Technology, LLC ("Alpha"), a company which sources treated wastewater from municipalities in Texas. Alpha is wholly-owned by Redtail.

Upon closing of the transaction, TEP obtained a controlling financial interest in Water Solutions and accordingly has accounted for the transaction as a step acquisition under ASC 805. On the acquisition date, TEP remeasured its previously held 50% equity interest in Redtail to its fair value of $11.9 million, recognized a gain of $9.4 million, and consolidated Water Solutions. The 20% equity interest in Water Solutions held by noncontrolling interests was recorded at its acquisition date fair value of $1.4 million. The fair values of the previously held equity interest and the noncontrolling interest were determined using a discounted cash flow analysis. These fair value measurements are based on significant inputs that are not observable in the market and thus represent fair value measurements categorized within Level 3 of the fair value hierarchy under ASC 820.

At December 31, 2014, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. During the three months ended June 30, 2015, the preliminary purchase price allocation with respect to Water Solutions was finalized with no material adjustments.

On May 20, 2015, TEP acquired an additional 12% equity interest in Water Solutions from NR2, LLC for cash consideration of $600,000, which was accounted for as an acquisition of noncontrolling interest. As of September 30, 2015, TEP's aggregate membership interest in Water Solutions was 92%.

5. Related Party Transactions

We have no employees. TD, through its wholly-owned subsidiary Tallgrass Operations, LLC ("Tallgrass Operations"), provided and charged us for direct and indirect costs of services provided to us or incurred on our behalf including employee labor costs, information technology services, employee health and retirement benefits, and all other expenses necessary or appropriate to the conduct of our business. We recorded these costs on the accrual basis in the period in which TD incurred them. On May 17, 2013, in connection with the closing of TEP’s initial public offering, TEP and its general partner entered into an Omnibus Agreement with TD and certain of its affiliates, including Tallgrass Operations (the "TEP Omnibus Agreement"). The TEP Omnibus Agreement provides that, among other things, TEP will reimburse TD and its affiliates for all expenses they incur and payments they make on TEP’s behalf, including the costs of employee and director compensation and benefits as well as the cost of the provision of certain centralized corporate functions performed by TD, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology and human resources in each case to the extent reasonably allocable to TEP. In addition, in connection with the closing of the Offering, TEGP entered into an Omnibus Agreement (the “TEGP Omnibus Agreement”) with TEGP Management, LLC, Tallgrass Equity and Holdings (which acts as the general partner of TD).

TEP’s general and administrative costs under the TEP Omnibus Agreement were $5.2 million and $16.1 million for the three and nine months ended September 30, 2015, respectively, excluding costs attributable to Pony Express. Pony Express had general and administrative costs of $5.2 million and $15.5 million for the three and nine months ended September 30, 2015, respectively. TEP also pays a quarterly reimbursement to TD for costs associated with being a public company, which was $635,000 for the third quarter of 2015. Pursuant to the TEGP Omnibus Agreement, Tallgrass Equity pays a reimbursement to TD for costs associated with TEGP being a public company beginning in the second quarter of 2015, which was $500,000 for the third quarter of 2015. These amounts will be periodically reviewed and adjusted as necessary to continue to reflect reasonable allocation of costs to TEP and TEGP, respectively.

Due to the cash management agreements discussed in Note 2 – Summary of Significant Accounting Policies, intercompany balances were periodically settled and treated as equity distributions prior to April 1, 2014 for Trailblazer and prior to September 1, 2014 for Pony Express. Balances lent to TD under the Pony Express cash management agreement effective September 1, 2014 are classified as related party receivables in the condensed consolidated balance sheets. During the nine months ended September 30, 2015 and 2014 we recognized interest income from TD of $0.4 million and $0.5 million, respectively, on the receivable balance under the Pony Express cash management agreement.

Totals of transactions with affiliated companies are as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(in thousands)
Cost of transportation services	$	7,180	$	—	$	17,771	$	—
Charges to TEGP: ⁽¹⁾
Property, plant and equipment, net	$	958	$	7,926	$	3,859	$	14,534
Operation and maintenance	$	6,077	$	4,701	$	17,325	$	13,657
General and administrative	$	10,041	$	5,783	$	28,862	$	14,670


⁽¹⁾	Charges to TEGP, inclusive of Tallgrass Equity, TEP, and Pony Express, include directly charged wages and salaries, other compensation and benefits, and shared services.

Details of balances with affiliates included in "Receivable from related party" and "Accounts payable to related parties" in the condensed consolidated balance sheets are as follows:



	September 30, 2015		December 31, 2014
	(in thousands)
Receivable from related party:
Tallgrass Operations, LLC	$	—	$	73,393
Total receivable from related party	$	—	$	73,393
Accounts payable to related parties:
Tallgrass Operations, LLC	$	3,561	$	3,894
Rockies Express Pipeline LLC	20		21
Total accounts payable to related parties	$	3,581	$	3,915

Balances of gas imbalances with affiliated shippers are as follows:



	September 30, 2015		December 31, 2014
	(in thousands)
Affiliate gas balance receivables	$	—	$	275
Affiliate gas balance payables	$	269	$	455

6. Inventory

The components of inventory at September 30, 2015 and December 31, 2014 consisted of the following:



	September 30, 2015		December 31, 2014
	(in thousands)
Crude oil	$	2,534	$	581
Materials and supplies	5,852		3,049
Natural gas liquids	345		519
Gas in underground storage	5,401		8,896
Total inventory	$	14,132	$	13,045

7. Property, Plant and Equipment

A summary of net property, plant and equipment by classification is as follows:



	September 30, 2015			December 31, 2014
	(in thousands)
Crude oil pipelines	$	1,159,002		$	939,536
Natural gas pipelines	556,924			548,482
Processing and treating assets	238,356			241,671
General and other	63,910			42,719
Construction work in progress	45,051			139,873
Accumulated depreciation and amortization	(114,422		)	(59,200		)
Total property, plant and equipment, net	$	1,948,821		$	1,853,081

8. Risk Management

We occasionally enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our normal business activities. Our normal business activities directly and indirectly expose us to risks associated with changes in the market price of crude oil and natural gas, among other commodities. For example, the risks associated with changes in the market price of natural gas include, among others (i) pre-existing or anticipated physical natural gas sales, (ii) natural gas purchases and (iii) natural gas system use and storage. We have elected not to apply hedge accounting and changes in the fair value of all derivative contracts are recorded in earnings in the period in which the change occurs.

Fair Value of Derivative Contracts

The following table summarizes the fair values of our derivative contracts included in the condensed consolidated balance sheets:



	Balance Sheet Location	September 30, 2015		December 31, 2014
		(in thousands)
Energy commodity derivative contracts	Current assets	$	218	$	—

As of September 30, 2015, the fair value shown for commodity contracts was comprised of derivative volumes for short natural gas fixed-price swaps totaling 0.6 Bcf. As of December 31, 2014 there were no derivative contracts outstanding.

Effect of Derivative Contracts in the Statements of Income

The following table summarizes the impact of derivative contracts for the three and nine months ended September 30, 2015 and 2014:



		Amount of Gain (Loss) Recognized in Income on Derivatives
	Location of gain (loss) recognized in income on derivatives	Three Months Ended September 30,				Nine Months Ended September 30,
	Location of gain (loss) recognized in income on derivatives	2015		2014		2015		2014
		(in thousands)
Derivatives not designated as hedging contracts:
Energy commodity derivative contracts	Sales of natural gas, NGLs, and crude oil	$	252	$	9	$	211	$	(449	)

Credit Risk

We have counterparty credit risk as a result of our use of derivative contracts. Our counterparties consist of major financial institutions. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

We maintain credit policies that we believe minimize our overall credit risk. These policies include (i) evaluation of potential counterparties’ financial condition (including credit ratings), (ii) collateral requirements under certain circumstances and (iii) the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty. Based on our policies and exposure, we do not currently anticipate a material adverse effect on our financial position, results of operations, or cash flows as a result of counterparty performance.

Our over-the-counter swaps are entered into with counterparties outside central trading organizations such as futures, options or stock exchanges. These contracts are with financial institutions with investment grade credit ratings. While we enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future. The maximum potential exposure to credit losses on TEP's derivative contracts at September 30, 2015 was:



	Asset Position
	(in thousands)
Gross	$	218
Netting agreement impact	—
Cash collateral held	—
Net Exposure	$	218

In addition, when the market value of our derivative contracts with specific counterparties exceeds established limits, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. Accordingly, entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability position with each counterparty. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account current credit spreads for its comparative industry sector, as well as any change in such spreads since the last measurement date. As of September 30, 2015 and December 31, 2014, we did not have any outstanding letters of credit or cash in margin accounts in support of our hedging of commodity price risks associated with the sale of natural gas nor did we have margin deposits with counterparties associated with energy commodity contract positions.

Fair Value

Derivative assets and liabilities are measured and reported at fair value. Derivative contracts can be exchange-traded or over-the-counter ("OTC"). Exchange-traded derivative contracts typically fall within Level 1 of the fair value hierarchy if they are traded in an active market. We value exchange-traded derivative contracts using quoted market prices for identical securities.

OTC derivatives are valued using models utilizing a variety of inputs including contractual terms and commodity and interest rate curves. The selection of a particular model and particular inputs to value an OTC derivative contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market. We use similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic forwards and swaps, model inputs can generally be verified and model selection does not involve significant management judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy.

Certain OTC derivative contracts trade in less liquid markets with limited pricing information; as such, the determination of fair value for these derivative contracts is inherently more difficult. Such contracts are classified within Level 3 of the fair value hierarchy. The valuations of these less liquid OTC derivatives are typically impacted by Level 1 and/or Level 2 inputs that can be observed in the market, as well as unobservable Level 3 inputs. Use of a different valuation model or different valuation input values could produce a significantly different estimate of fair value. However, derivative contracts valued using inputs unobservable in active markets are generally not material to our financial statements.

When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used.

The following table summarizes the fair value measurements of our energy commodity derivative contracts as of September 30, 2015 based on the fair value hierarchy established by the Codification:



			Asset Fair Value Measurements Using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
	(in thousands)
As of September 30, 2015
Energy commodity derivative contracts	$	218	$	—	$	218	$	—

9. Long-term Debt

Tallgrass Equity Credit Facility

The following table sets forth the available borrowing capacity under the Tallgrass Equity revolving credit facility as of September 30, 2015 and December 31, 2014:



	September 30, 2015			December 31, 2014
	(in thousands)
Total capacity under the Tallgrass Equity revolving credit facility	$	150,000		$	—
Less: Outstanding borrowings under the Tallgrass Equity revolving credit facility	(148,000		)	—
Available capacity under the Tallgrass Equity revolving credit facility	$	2,000		$	—

In connection with the Offering, Tallgrass Equity entered into a $150 million senior secured revolving credit facility with Barclays Bank PLC, as administrative agent, and a syndicate of lenders, which will mature on May 12, 2020. The Tallgrass Equity credit facility includes a $10 million sublimit for letters of credit and a $10 million sublimit for swing line loans. The Tallgrass Equity revolving credit facility may be used (i) to pay transaction costs and any fees and expenses incurred in connection with the revolving credit facility and certain transactions relating to the Offering, (ii) to fund the purchase of the Acquired TEP Units and (iii) for general Partnership purposes, including distributions. The Tallgrass Equity revolving credit facility also contains an accordion feature whereby Tallgrass Equity can increase the size of the credit facility to an aggregate of $200 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions precedent. In addition, Tallgrass Equity is required to maintain a total leverage ratio of not more than 3.00 to 1.00. As of September 30, 2015, Tallgrass Equity was in compliance with the covenants required under the revolving credit facility.

Upon the close of the Offering, Tallgrass Equity had $150 million in outstanding borrowings under the credit facility, of which $3 million was subsequently repaid using proceeds from the Offering retained from the distribution of Excess Proceeds to the Exchange Right Holders for short term working capital needs, which will ultimately be distributed to the Exchange Right Holders to the extent not used to pay offering expenses and other transaction costs. An additional $1.0 million was borrowed during the three months ended September 30, 2015, leaving $2 million in remaining capacity available for future borrowings or letter of credit issuances as of September 30, 2015. The initial borrowings under the credit facility were used to fund a portion of the purchase of the Acquired TEP Units and to pay origination and arrangement fees associated with the new revolving credit facility and transaction costs associated with the Offering. Tallgrass Equity’s obligations under the revolving credit facility are secured by a first priority lien on all of the present and after acquired equity interests held by Tallgrass Equity in TEP GP and TEP. Borrowings under the credit facility bear interest, at Tallgrass Equity’s option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar rate, plus, in each case, an applicable margin. For loans bearing interest based on the base rate, the applicable margin is 1.50%, and for loans bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin is 2.50%. The unused portion of the revolving credit facility is subject to a commitment fee of 0.50%. As of September 30, 2015, the weighted average interest rate on outstanding borrowings was 2.71%.

TEP Credit Facility

The following table sets forth the available borrowing capacity under the TEP revolving credit facility as of September 30, 2015 and December 31, 2014:



	September 30, 2015			December 31, 2014
	(in thousands)
Total capacity under the TEP revolving credit facility	$	850,000		$	850,000
Less: Outstanding borrowings under the TEP revolving credit facility	(696,000		)	(559,000		)
Available capacity under the TEP revolving credit facility	$	154,000		$	291,000

The TEP revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict TEP’s ability (as well as the ability of TEP’s restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions (including distributions from available cash, if a default or event of default under the credit agreement then exists or would result from making such a distribution), change the nature of TEP’s business, engage in certain mergers or make certain investments and acquisitions, enter into non-arms-length transactions with affiliates and designate certain subsidiaries as "Unrestricted Subsidiaries." In addition, TEP is required to maintain a consolidated leverage ratio of not more than 4.75 to 1.00 (which will be increased to 5.25 to 1.00 for certain measurement periods following the consummation of certain acquisitions) and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of September 30, 2015, TEP is in compliance with the covenants required under the TEP revolving credit facility. The unused portion of the revolving credit facility is subject to a commitment fee, which ranges from 0.300% to 0.500%, based on TEP’s total leverage ratio. As of September 30, 2015, the weighted average interest rate on outstanding borrowings was 1.97%.

Fair Value

The following table sets forth the carrying amount and fair value of our long-term debt, which is not measured at fair value in the condensed consolidated balance sheets as of September 30, 2015 and December 31, 2014, but for which fair value is disclosed:



	Fair Value
	Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)		Total		Carrying Amount
	(in thousands)
September 30, 2015	$	—	$	844,000	$	—	$	844,000	$	844,000
December 31, 2014	$	—	$	559,000	$	—	$	559,000	$	559,000

The long-term debt borrowed under the revolving credit facility is carried at amortized cost. As of September 30, 2015 and December 31, 2014, the fair value approximates the carrying amount for the borrowings under our revolving credit facilities using a discounted cash flow analysis. We are not aware of any factors that would significantly affect the estimated fair value subsequent to September 30, 2015.

10. Partnership Equity and Distributions

TEP February Public Offering

On February 27, 2015, TEP sold 10,000,000 common units representing limited partner interests in an underwritten public offering at a price of $50.82 per unit, or $49.29 per unit net of the underwriter's discount, for net proceeds of approximately $492.4 million after deducting the underwriter's discount and offering expenses paid by TEP. TEP used the net proceeds from the offering to fund a portion of the consideration for the acquisition of an additional 33.3% membership interest in Pony Express as discussed in Note 4 – Acquisitions. Pursuant to the underwriters' option to purchase additional units, TEP sold an additional 1,200,000 common units representing limited partner interests to the underwriters at a price of $50.82 per unit, or $49.29 per unit net of the underwriter’s discount, for net proceeds of approximately $59.3 million after deducting the underwriter’s discount and offering expenses paid by TEP. TEP used the net proceeds from this additional purchase of common units to reduce borrowings under its revolving credit facility, a portion of which were used to fund the March 2015 acquisition of an additional 33.3% membership interest in Pony Express as discussed in Note 4 – Acquisitions.

TEGP Partnership Agreement and Distributions to Holders of Class A Shares

On May 12, 2015, TEGP closed the Offering and completed the Reorganization Transactions as outlined in Note 1 – Description of Business. In connection with the Offering, TEGP entered into an amended and restated partnership agreement on May 12, 2015. The partnership agreement requires TEGP to distribute its available cash to Class A shareholders on a quarterly basis, subject to certain terms and conditions, beginning with the quarter ended June 30, 2015. The following table details the distributions paid by TEGP during the nine months ended September 30, 2015:



Three Months Ended	Date Paid	Distributions to Class A Shareholders		Distributions per Class A Share
		(in thousands)
September 30, 2015	November 13, 2015⁽¹⁾	$	6,872	$	0.144
June 30, 2015	August 17, 2015	3,484		0.073		⁽²⁾


⁽¹⁾	The distribution for the third quarter of 2015 will be paid on November 13, 2015 to Class A shareholders of record at the close of business on October 30, 2015.


⁽²⁾	The first quarterly distribution declared on July 15, 2015 was prorated for the number of days between the closing of TEGP’s initial public offering on May 12, 2015 and the end of the second quarter.

Exchange Rights

The Exchange Right Holders and any permitted transferees of their Tallgrass Equity units each have the right to exchange all or a portion of their Tallgrass Equity units for Class A shares at an exchange ratio of one Class A share for each Tallgrass Equity unit exchanged, which we refer to as the Exchange Right. The Exchange Right may be exercised only if, simultaneously therewith, an equal number of our Class B shares are transferred by the exercising party to us. Upon such exchange, we will cancel the Class B shares received from the exercising party.

Noncontrolling Interests

As of September 30, 2015, noncontrolling interests in our subsidiaries consisted of a 69.65% interest in Tallgrass Equity held by the Exchange Right Holders, the 66.07% limited partner interest in TEP held by TD and the public TEP unitholders, the 33.3% membership interest in Pony Express held by TD, and an 8% membership interest in Water Solutions. During the nine months ended September 30, 2015, we recognized contributions to and distributions from TEP's noncontrolling interests of $110.6 million and $44.5 million, respectively, consisting primarily of contributions and distributions between Pony Express and TD.

Subsidiary Distributions

TEP Distributions. The following table details the distributions paid by TEP during the nine months ended September 30, 2015:



		Distributions
		Limited Partner Units		General Partner						Distributions per Limited Partner Unit
Three Months Ended	Date Paid	Limited Partner Units		Incentive Distribution Rights		General Partner Units		Total		Distributions per Limited Partner Unit
		(in thousands, except per unit amounts)
September 30, 2015	November 13, 2015⁽¹⁾	$	36,347	$	11,567	$	660	$	48,574	$	0.6000
June 30, 2015	August 14, 2015	35,135		10,418		627		46,180		0.5800
March 31, 2015	May 14, 2015	31,322		6,934		530		38,786		0.5200
December 31, 2014	February 13, 2015	23,782		4,039		473		28,294		0.4850


⁽¹⁾	The distribution for the third quarter of 2015 will be paid on November 13, 2015 to unitholders of record at the close of business on October 30, 2015.

Other Contributions and Distributions

During the nine months ended September 30, 2015, we distributed $334.1 million of Excess Proceeds from the Offering to the Exchange Right Holders as part of the Reorganization Transactions and distributed $13.5 million to the TEGP Predecessor. In addition, we received $7.5 million of TEP general partner and IDR distributions related to periods prior to the Offering which were distributed to the previous TEP GP Members, and $13.0 million of TEP distributions received which were distributed by Tallgrass Equity to the Exchange Right Holders. Also during the nine months ended September 30, 2015, we received contributions from and made distributions to TEP's noncontrolling interests of $110.6 million and $44.5 million, respectively.

During the nine months ended September 30, 2014, we recognized net contributions from the TEGP Predecessor of $289.4 million. This activity represents transfers of cash as a result of TD’s centralized cash management systems as discussed in Note 1 – Description of Business, as well as the TEP distributions paid on the Acquired TEP Units and distributions paid for excess offering proceeds. We also recognized a $27.5 million contribution from TD representing the difference between the carrying amount of the Replacement Gas Facilities required as part of the Pony Express Abandonment, as discussed in Note 13 – Regulatory Matters, and the proceeds received from TD as reimbursement for the costs to construct those assets. Also during the nine months ended September 30, 2014, we received contributions from and made distributions to noncontrolling interests of $5.4 million and $37,000, respectively.

11. Net Income per Class A Share

Basic net income per Class A share is determined by dividing net income attributable to TEGP by the weighted average number of outstanding Class A shares during the period. Class B shares do not share in the earnings of the Partnership. Accordingly, basic and diluted net income per Class B share has not been presented.

Diluted net income per Class A share is determined by dividing net income attributable to TEGP by the weighted average number of outstanding diluted Class A shares during the period. For purposes of calculating diluted net income per Class A share, we considered the impact of possible future exercises of the Exchange Right by the Exchange Right Holders on both net income attributable to TEGP and the diluted weighted average number of Class A shares outstanding. Pursuant to the TEGP partnership agreement and the Tallgrass Equity limited liability company agreement, our capital structure and the capital structure of Tallgrass Equity will generally replicate one another in order to maintain the one-for-one exchange ratio between the Tallgrass Equity units and Class B shares, on the one hand, and our Class A shares, on the other hand. As a result, the potential exchange of any Class B shares does not have a dilutive effect on basic net income per Class A share. For the three and nine months ended September 30, 2015 the possible exchange of any TEGP Equity Participation units would have had a dilutive effect on basic net income per Class A share.

Net income per Class A share is not presented for the three and nine months ended September 30, 2014 as there were no Class A shares outstanding during those periods. The Offering became effective during the second quarter of 2015. As a result, no income from the period from January 1, 2015 through May 11, 2015 is allocated to the Class A shares that were issued on May 12, 2015.

The following table illustrates the calculation of basic and diluted net income per Class A share for the three and nine months ended September 30, 2015 (in thousands, except per share data):



	Three Months Ended September 30, 2015		Nine Months Ended September 30, 2015
	(in thousands, except per unit amounts)
Basic Net Income per Class A Share:
Net income attributable to TEGP	$	4,423	$	14,279
Net income attributable to TEGP from the beginning of the period to May 11, 2015	—		7,393
Net income attributable to TEGP from May 12, 2015 to September 30, 2015	$	4,423	$	6,886
Basic weighted average Class A Shares outstanding	47,725		47,725
Basic net income per Class A share	$	0.09	$	0.14

Diluted Net Income per Class A Share:
Net income attributable to TEGP from May 12, 2015 to September 30, 2015	$	4,423	$	6,886
Incremental net income attributable to TEGP including the effect of the assumed issuance of Equity Participation Shares from May 12, 2015 to September 30, 2015	2		2
Net income attributable to TEGP including incremental net income from assumed issuance of Equity Participation Shares from May 12, 2015 to September 30, 2015	$	4,425	$	6,888
Basic weighted average Class A Shares outstanding	47,725		47,725
Equity Participation Shares equivalent shares	83		87
Diluted weighted average Class A Shares outstanding	47,808		47,812
Diluted net income per Class A Share	$	0.09	$	0.14

12. Equity-Based Compensation

Long-Term Incentive Plan

Effective May 12, 2015, our general partner adopted the TEGP Management, LLC Long-Term Incentive Plan (“LTIP”) on our behalf for (i) the employees of our general partner and its affiliates who perform services for us, (ii) the non-employee directors of our general partner and (iii) the consultants who perform services for us. Awards under the LTIP will consist of unrestricted shares, restricted shares, equity participation shares, options and share appreciation rights. The LTIP will limit the number of shares that may be delivered pursuant to awards to 3,144,589 Class A shares (subject to any adjustment due to recapitalization, reorganization or a similar event permitted under the LTIP). Shares that are forfeited or withheld to satisfy exercise price or tax withholding obligations are available for delivery pursuant to other awards.

Equity Participation Shares

On May 12, 2015, the board of directors of our general partner approved the grant of up to 3,144,589 Class A shares (subject to any adjustment due to recapitalization, reorganization or a similar event permitted under the LTIP) under the LTIP. Effective August 1, 2015, 160,000 Equity Participation Shares were granted to employees. Vesting of the Equity Participation Shares is contingent on certain service and performance conditions. The Equity Participation Shares vest on the later to occur of the Distribution Achievement Date (the first date on which TEGP pays a regular quarterly distribution of at least $0.35 for any full quarter ending on or after the Grant Date), or May 12, 2019. If the Distribution Achievement Date has not occurred by May 12, 2020, the Equity Participation Shares will expire and terminate and no vesting will occur. The Equity Participation Shares are non-participating, as such participants are not entitled to receive any distributions with respect to the Equity Participation Shares unless the participant receives a separate grant of Distribution Equivalent Rights. At this time no grants of Distribution Equivalent Rights have been made.

The Equity Participation Share grants were measured at their grant date fair value of $27.97 per Equity Participation Share. The Equity Participation Shares are non-participating, therefore the grant date fair value is discounted from the grant date fair value of TEGP's Class A shares for the present value of the expected future dividends during the vesting period. Equity-based compensation cost related to the Equity Participation Share grants of approximately $0.2 million was recognized during the three and nine months ended September 30, 2015. As of September 30, 2015, $4.3 million of compensation cost related to non-vested Equity Participation Shares is expected to be recognized over a weighted-average period of 3.8 years. The compensation expense recognized is allocated between TEGP, inclusive of TEP, and TD.

13. Regulatory Matters

There are currently no proceedings challenging the currently effective rates of Pony Express, TIGT, or Trailblazer. Regulators, as well as shippers, do have rights, under circumstances prescribed by applicable regulations, to challenge the rates that we charge at our regulated entities. Further, the statute governing service by Pony Express allows parties having standing to file complaints in regard to existing tariff rates and provisions. If the complaint is not resolved, the FERC may conduct a hearing and order a crude oil pipeline to make reparations going back for up to two years prior to the date on which a complaint was filed if a rate is found to be unjust and unreasonable. We can provide no assurance that current rates will remain unchallenged. Any successful challenge could have a material, adverse effect on our future earnings and cash flows.

TIGT

Pony Express Abandonment – FERC Docket CP12-495

On August 6, 2012, TIGT filed an application to: (1) abandon for FERC purposes approximately 433 miles of mainline natural gas pipeline facilities, along with associated rights of way and other related equipment (collectively, the "Pony Express Assets"), and the natural gas service therefrom, by transferring those assets to Pony Express, which subsequently converted the Pony Express Assets into crude oil pipeline facilities; and (2) construct and operate certain replacement-type facilities necessary to continue service to existing natural gas firm transportation customers following the conversion, which we refer to as the Replacement Gas Facilities. This project is referred to as the "Pony Express Abandonment." The FERC abandonment does not constitute an abandonment for accounting purposes. Pursuant to the terms of the Purchase and Sale Agreement filed with the FERC and cited by the FERC in approving the Pony Express Abandonment, Pony Express is required to reimburse TIGT for the net book value of the Pony Express Assets plus other TIGT incurred costs required to construct the Replacement Gas Facilities and to arrange substitute gas transportation services to certain TIGT shippers.

The Pony Express Abandonment and completion of the Pony Express Project by Pony Express re-deployed existing pipeline assets to meet the growing market need to transport oil supplies while at the same time continuing to operate TIGT’s natural gas transportation facilities to meet all current and expected needs of its natural gas customers. By a FERC order issued September 12, 2013, TIGT was granted authorization to abandon the Pony Express Assets and construct the Replacement Gas Facilities. On October 7, 2013 TIGT commenced the mobilization of personnel and equipment for the construction of the Replacement Gas Facilities necessary to complete the Pony Express Abandonment to continue service to existing TIGT customers. In December 2013, TIGT removed the Pony Express Assets from gas service and sold those assets to Pony Express. On May 1, 2014, TIGT commenced commercial service through all of the Replacement Gas Facilities, with the exception of Units 3 and 4 at the Tescott Compressor Station. Service through Units 3 and 4 at the Tescott Compressor Station commenced on May 30, 2014.

Cost and Revenue Study – FERC Docket RP11-1494

On October 3, 2015, TIGT submitted a cost and revenue study in compliance with Article IV of the Stipulation and Agreement of Settlement filed on May 5, 2011 in FERC Docket No. RP11-1494 (“2011 Settlement”) and approved by the FERC on September 22, 2011. Consistent with the 2011 Settlement, the cost and revenue study demonstrates that TIGT is under-recovering its cost of service. The study was based on the unadjusted actual costs, revenues and volumes for a 12-month base period ended June 30, 2015, that complies with Section 154.303(a)(1) of the FERC’s regulations. The cost and revenue study did not propose any change to TIGT’s currently effective rates. Instead, TIGT has filed a general rate case under Section 4 of the Natural Gas Act, as discussed further below.

General Rate Case Filing – FERC Docket RP16-137

On October 30, 2015, TIGT filed a general rate case with the FERC pursuant to section 4 of the Natural Gas Act. The rate case proposes a general system-wide increase in the maximum tariff rates for all firm and interruptible services offered by TIGT. In addition, TIGT proposed certain changes to the transportation rate design of its system to replace the current rate zone structure with a single “postage stamp” rate. TIGT also proposed new charges, including (i) a charge for deliveries made to points without certain electronic flow measurement equipment, and (ii) a charge to completely or partially reimburse TIGT for certain integrity related expenses and costs it incurs to comply with anticipated new PHMSA and EPA regulations. TIGT also proposed to replace its fixed fuel and lost and unaccounted for (“FL&U”) charge with a FL&U tracker that would compensate TIGT for its actual FL&U expenses and adjust each year to reflect the previous period’s under or over collection and the forecasted FL&U expense for the upcoming period. Finally, TIGT proposed certain revisions to its FERC Gas Tariff addressing a number of other rate and non-rate matters. Under the NGA and the FERC’s regulations, TIGT’s shippers and other interested parties, including the FERC’s Trial Staff, have a right to challenge any aspect of TIGT’s rate case filing or raise other issues under Section 5 of the Natural Gas Act for which only prospective relief is available.

Trailblazer

2013 Rate Case Filing - Docket No. RP13-1031

On January 22, 2014, Trailblazer, the FERC’s Trial Staff, and the active parties in the pipeline’s general rate case finalized a settlement in principle resolving the pending rate issues, including: (i) establishing transportation rates, as well as fuel and lost and unaccounted for charges; (ii) providing a limited profit sharing arrangement for certain revenues earned from interruptible and short-term firm transport; and (iii) setting the minimum and maximum time that can elapse before Trailblazer’s next rate case at the FERC. Trailblazer filed a motion with the FERC’s Chief Administrative Law Judge to accept the settlement rates on an interim basis ("Interim Rates") while the participants finalized a definitive settlement. The Chief Administrative Law Judge accepted the Interim Rates effective February 1, 2014. On February 24, 2014, Trailblazer filed an uncontested offer of settlement ("Stipulation and Agreement") among active party shippers. The Stipulation and Agreement established the Interim Rates as final settlement rates effective February 1, 2014, subject to the issuance of refunds to certain shippers for January 2014 transportation services and revised fuel and lost and unaccounted for rates, effective July 1, 2014. On March 11, 2014, the Presiding Administrative Law Judge certified the Stipulation and Agreement. On May 29, 2014, the FERC approved the Stipulation and Agreement. On June 30, 2014, Trailblazer filed tariff sheets to implement the Stipulation and Agreement effective July 1, 2014. Estimated refunds were reserved from revenues recorded in January 2014. On July 1, 2014, Trailblazer submitted refunds to its customers for amounts collected in excess of amounts that would have been collected under the Settlement Rates, with interest, and on July 18, 2014, filed a report of refunds with the FERC. The FERC issued orders accepting the tariff sheets with the requested effective date of July 1, 2014 and accepting the refund report filing on July 25, 2014 and August 7, 2014, respectively.

2015 Annual Fuel Tracker Filing - Docket No. RP15-841-000

On April 1, 2015, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2015 in Docket No. RP15-841-000. This filing incorporates the revised fuel tracker and power cost tracker mechanisms agreed to in the 2013 Rate Case Filing settlement, which resolves all outstanding issues related to Trailblazer fuel recoveries. The FERC approved this filing on April 23, 2015.

Pony Express

On September 19, 2014, Pony Express filed with the FERC to adopt a tariff for initial local non-contract rates as well as initial Rules and Regulations in accordance with the Interstate Commerce Act to be effective starting on October 1, 2014. Local Contract Tariff rates were filed with the FERC on October 29, 2014 to be effective starting November 1, 2014. Joint Contract Tariff rates for oil received into the Pony Express System from the Belle Fourche Pipeline were filed on October 16, 2014 to be effective starting November 1, 2014. Joint Contract Tariff rates for oil received into the Pony Express pipeline system from Hiland Pipeline Company were filed on February 27, 2015 and effective April 1, 2015.

On May 18, 2015, Pony Express filed with the FERC to implement tariff contract rates for Pony Express’ newly constructed lateral in Northeast Colorado effective June 1, 2015.

On May 29, 2015, tariff filings were made with the FERC in Docket No. IS15-492-000 to increase the Pony Express local contract rates for service from the Guernsey origin, and for local non-contract rates from all origins, by amounts reflecting the FERC annual index adjustment of approximately 4.6% effective July 1, 2015. A tariff filing was also made in Docket No. IS15-493-000 on that date to increase joint tariff contract rates for service on Pony Express, Belle Fourche Pipeline Company, and Bridger Pipeline, LLC by approximately 4.6% effective July 1, 2015.

On October 29, 2015, Pony Express made a tariff filing with the FERC in Docket No. IS16-42-000 to increase the contract rates under its Local Pipeline Tariff for transportation from receipt points on its lateral in Northeast Colorado to various delivery points in Oklahoma, by an amount reflecting the most recent FERC annual index adjustment of approximately 4.6% effective December 1, 2015.

14. Legal and Environmental Matters

Legal

In addition to the matters discussed below, we are a defendant in various lawsuits arising from the day-to-day operations of our business. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such routine items will not have a material adverse impact on our business, financial position, results of operations or cash flows.

We have evaluated claims in accordance with the accounting guidance for contingencies that we deem both probable and reasonably estimable and, accordingly, had reserves for legal claims of approximately $0.8 million and $0.6 million as of September 30, 2015 and December 31, 2014, respectively.

Prairie Horizon

On July 3, 2014, Prairie Horizon Agri-Energy LLC ("Prairie Horizon") filed an action in the District Court of Phillips County, Kansas against TIGT seeking damages from an alleged intrusion of foreign material and oil from TIGT into Prairie Horizon's ethanol plant. The matter was removed to the US District Court for the District of Kansas. Prairie Horizon asserted that this intrusion caused substantial damage to Prairie Horizon's ethanol production facilities and resulted in corresponding business income losses. Prairie Horizon also claimed that the intrusion was a violation of TIGT's FERC gas tariff. On September 25, 2015, TIGT and Prairie Horizon reached a settlement agreeing to dismiss all claims with prejudice and releasing TIGT from any further liability.

Environmental, Health and Safety

We are subject to a variety of federal, state and local laws that regulate permitted activities relating to air and water quality, waste disposal, and other environmental matters. We believe that compliance with these laws will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause us to incur significant costs. We had environmental reserves of $5.0 million and $5.3 million at September 30, 2015 and December 31, 2014, respectively.

TMID

Casper Plant, U.S. EPA Notice of Violation

In August 2011, the U.S. EPA and the Wyoming Department of Environmental Quality ("WDEQ") conducted an inspection of the Leak Detection and Repair ("LDAR") Program at the Casper Gas Plant in Wyoming. In September 2011, Tallgrass Midstream, LLC ("TMID") received a letter from the U.S. EPA alleging violations of the Standards of Performance of Equipment Leaks for Onshore Natural Gas Processing Plant requirements under the Clean Air Act. TMID received a letter from the U.S. EPA concerning settlement of this matter in April 2013 and received additional settlement communications from the U.S. EPA and Department of Justice beginning in July 2014. Settlement negotiations are continuing, including attempted resolution of more recently identified LDAR issues and the possible inclusion of TIGT as a party to any possible settlement as a result of TIGT owning a compressor that is located adjacent to the Casper Gas Plant site.

Casper Mystery Bridge Superfund Site

The Casper Gas Plant is part of the Mystery Bridge Road/U.S. Highway 20 Superfund Site also known as Casper Mystery Bridge Superfund Site. Remediation work at the Casper Gas Plant has been completed and we have requested that the portion of the site attributable to us be delisted from the National Priorities List.

Casper Gas Plant

On November 25, 2014, WDEQ issued a Notice of Violation for violations of Part 60 Subpart OOOO related to the Depropanizer project (wv-14388, issued 7/9/13) in Docket No. 5506-14. TMID had discussed the issues in a meeting with WDEQ in Cheyenne on November 17, 2014, and submitted a disclosure on November 20, 2014 detailing the regulatory issues and potential violations. The project triggered a modification of Subpart OOOO for the entire plant. The project equipment as well as plant equipment subjected to Subpart OOOO was not monitored timely, and initial notification was not made timely. Settlement negotiations with WDEQ are currently ongoing.

TIGT

System Failure

On June 13, 2013, a failure occurred on a segment of the TIGT pipeline system in Goshen County, Wyoming, resulting in the release of natural gas and the issuance of a Corrective Action Order ("CAO") by PHMSA. The line was promptly brought back into service and the failure did not cause any known injuries, fatalities, fires or evacuations. Pursuant to a letter dated August 14, 2015, PHMSA informed TIGT that it had complied with the terms of the CAO and declared the case closed. We do not believe the total cost to complete the remediation activities will be material.

Trailblazer

Pipeline Integrity Management Program

Trailblazer recently completed smart tool surveys and preliminary analysis on segments of its natural gas pipeline to evaluate the growth rate of corrosion downstream of compressor stations. Trailblazer currently believes that approximately 25 - 35 miles of pipe will likely need to be repaired or replaced in order for the pipeline to operate at its maximum allowable operating pressure of 1,000 pounds per square inch, or psig. Such repair or replacement may occur over a period of years, depending upon final assessment of corrosion growth rates and the remediation and repair plan adopted by Trailblazer. Until then, Trailblazer is operating at a reduced pressure, public notice of which was first provided in June 2014. The current pressure reduction is not expected to prevent Trailblazer from fulfilling its firm service obligations at existing subscription levels and to date it has not had a material adverse financial impact on TEP.

During 2015, Trailblazer completed 23 excavation digs at an aggregate cost of approximately $1.1 million (all of which was included in Trailblazer’s 2015 budget) based on preliminary analysis of the smart tool surveys performed in 2014. Segments of the Trailblazer Pipeline that require full replacement are currently expected to cost in the range of approximately $2.2 million to $2.7 million per mile. Repair costs on sections of the pipeline that do not require full replacement are expected to be less on a per mile basis. Trailblazer is currently devising a remediation and repair plan, which involves, among other things, finalizing cost recovery options, establishing project scope and timing and setting an overall project budget. Trailblazer is currently exploring all possible cost recovery options. It may not ultimately be able to recover any or all of such out of pocket costs unless and until Trailblazer recovers them through a general rate increase or other FERC-approved recovery mechanism, or through negotiated rate agreements with its customers.

In connection with TEP’s acquisition of the Trailblazer Pipeline, TD agreed to contractually indemnify TEP for any out of pocket costs TEP incurs between April 1, 2014 and April 1, 2017 related to repairing or remediating the Trailblazer Pipeline, to the extent that such actions are necessitated by external corrosion caused by the pipeline’s disbonded Hi-Melt CTE coating. The contractual indemnity provided to TEP by TD is currently capped at $20 million and is subject to TEP’s first paying an annual $1.5 million deductible.

Pony Express

System Failures

On August 31, 2014, a leak occurred at the Sterling Pump Station on the Pony Express System in Logan County, Colorado, which resulted in a release of approximately 200 bbls of crude oil. The spill was entirely contained on our property and the costs to remediate were not material. In April 2015, PHSMA granted our request to consider the Sterling Pump Station incident closed with no further action.

On March 12, 2015, an event occurred at the Yoder Pump Station in Goshen County, Wyoming, related to repair and replacement activities resulting in a spill of approximately 300 bbls of crude oil. We have presented our incident investigation findings to PHMSA and are currently working with PHMSA to resolve the matter. We do not believe the cost of anticipated remediation activities will be material.

15. Reporting Segments

Our operations are located in the United States. We are organized into three reporting segments: (1) Natural Gas Transportation & Logistics, (2) Crude Oil Transportation & Logistics, and (3) Processing & Logistics.

Natural Gas Transportation & Logistics

The Natural Gas Transportation & Logistics segment is engaged in ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities that provide services to on-system customers (such as third-party LDCs), industrial users and other shippers. As discussed in Note 2 – Summary of Significant Accounting Policies, results for prior periods have been recast to reflect the operations of Trailblazer.

Crude Oil Transportation & Logistics

The Crude Oil Transportation & Logistics segment is engaged in ownership, construction, and operation of the Pony Express System, which is a FERC-regulated crude oil pipeline serving the Bakken Shale and other nearby oil producing basins. The mainline portion of the Pony Express System was placed in service in October 2014. The Pony Express System also includes a lateral pipeline in Northeast Colorado, which interconnects with the Pony Express System just east of Sterling, Colorado and was placed in service in April 2015. As discussed in Note 2 – Summary of Significant Accounting Policies, results for prior periods have been recast to reflect the operations of Pony Express.

Processing & Logistics

The Processing & Logistics segment is engaged in ownership and operation of natural gas processing, treating and fractionation facilities that produce NGLs and residue gas that is sold in local wholesale markets or delivered into pipelines for transportation to additional end markets, as well as water business services provided primarily to the oil and gas exploration and production industry.

Corporate and Other

Corporate and Other includes corporate overhead costs that are not directly associated with the operations of our reportable segments, such as interest and fees associated with our revolving credit facilities, public company costs reimbursed to TD, and equity-based compensation expense.

These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for their respective operations. We measure segment profit using Operating Income.

The following tables set forth our segment information for the periods indicated:



	Three Months Ended September 30, 2015							Three Months Ended September 30, 2014
Revenue:	Total Revenue		Inter- Segment			External Revenue		Total Revenue		Inter- Segment			External Revenue
	(in thousands)							(in thousands)
Natural Gas Transportation & Logistics	$	33,636	$	(1,346	)	$	32,290	$	33,520	$	(1,430	)	$	32,090
Crude Oil Transportation & Logistics	83,272		—			83,272		—		—			—
Processing & Logistics	22,606		—			22,606		57,863		—			57,863
Total Revenue	$	139,514	$	(1,346	)	$	138,168	$	91,383	$	(1,430	)	$	89,953



	Nine Months Ended September 30, 2015							Nine Months Ended September 30, 2014
Revenue:	Total Revenue		Inter- Segment			External Revenue		Total Revenue		Inter- Segment			External Revenue
	(in thousands)							(in thousands)
Natural Gas Transportation & Logistics	$	98,215	$	(4,036	)	$	94,179	$	107,091	$	(4,015	)	$	103,076
Crude Oil Transportation & Logistics	208,872		—			208,872		—		—			—
Processing & Logistics	82,762		—			82,762		158,976		—			158,976
Total Revenue	$	389,849	$	(4,036	)	$	385,813	$	266,067	$	(4,015	)	$	262,052



	Three Months Ended September 30, 2015									Three Months Ended September 30, 2014
Operating Income:	Total Operating Income			Inter- Segment			External Operating Income			Total Operating Income			Inter- Segment			External Operating Income
				(in thousands)									(in thousands)
Natural Gas Transportation & Logistics	$	10,499		$	(1,346	)	$	9,153		$	10,791		$	(1,430	)	$	9,361
Crude Oil Transportation & Logistics	44,069			1,346			45,415			(822		)	—			$	(822	)
Processing & Logistics	(212		)	—			(212		)	5,141			—			$	5,141
Corporate and Other	(1,951		)	—			(1,951		)	(2,100		)	—			$	(2,100	)
Total Operating Income	$	52,405		$	—		$	52,405		$	13,010		$	(1,430	)	$	11,580
Reconciliation to Net Income:
Interest expense, net							(4,982		)							(1,058		)
Other income, net							502									731
Net Income before income tax							$	47,925								$	11,253



	Nine Months Ended September 30, 2015									Nine Months Ended September 30, 2014
Operating Income:	Total Operating Income			Inter- Segment			External Operating Income			Total Operating Income			Inter- Segment			External Operating Income
				(in thousands)									(in thousands)
Natural Gas Transportation & Logistics	$	32,989		$	(4,036	)	$	28,953		$	32,075		$	(4,015	)	$	28,060
Crude Oil Transportation & Logistics	103,857			4,036			$	107,893		(2,336		)	—			$	(2,336	)
Processing & Logistics	4,508			—			$	4,508		14,459			—			$	14,459
Corporate and Other	(7,126		)	—			$	(7,126	)	(5,599		)	—			$	(5,599	)
Total Operating Income	$	134,228		$	—		$	134,228		$	38,599		$	(4,015	)	$	34,584
Reconciliation to Net Income:
Interest expense, net							(12,901		)							(4,492		)
Gain on remeasurement of unconsolidated investment							—									9,388
Equity in earnings of unconsolidated investment							—									717
Other income, net							1,983									2,400
Net Income before income tax							$	123,310								$	42,597



	Nine Months Ended September 30,
Capital Expenditures:	2015		2014
	(in thousands)
Natural Gas Transportation & Logistics	$	10,858	$	16,616
Crude Oil Transportation & Logistics	40,579		617,687
Processing & Logistics	13,709		7,913
Total capital expenditures	$	65,146	$	642,216



Assets:	September 30, 2015		December 31, 2014
	(in thousands)
Natural Gas Transportation & Logistics	$	713,754	$	716,106
Crude Oil Transportation & Logistics	1,444,231		1,394,793
Processing & Logistics	337,522		340,620
Corporate and Other	449,220		5,678
Total assets	$	2,944,727	$	2,457,197

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

The historical financial statements included in this Quarterly Report reflect the consolidated results of operations of Tallgrass Energy GP, LP ("TEGP")'s 30.35% interest in Tallgrass Equity, LLC ("Tallgrass Equity"), Tallgrass Equity's 100% membership interest in Tallgrass MLP GP, LLC ("TEP GP"), which owns all of the Incentive Distribution Rights, or IDRs, and all of the outstanding general partner units in Tallgrass Energy Partners, LP ("TEP"), and Tallgrass Equity's 20 million TEP common units it acquired at the closing of the initial public offering of Class A shares of TEGP (the "Offering"). In connection with the closing of the Offering on May 12, 2015, the following transactions (the “Reorganization Transactions”) occurred (i) Tallgrass Equity distributed its interests in Tallgrass Energy Holdings, LLC ("Holdings") and Holdings distributed its existing limited partner interest in TEGP, respectively, to the owners of Tallgrass Equity that also collectively own 100% of the voting power of Holdings, which are referred to as the “Exchange Right Holders;” (ii) TEGP issued 47,725,000 Class A shares to the public (including 6,225,000 Class A shares issued in connection with the underwriters' exercise of the overallotment option) for net proceeds of approximately $1.3 billion; (iii) the existing limited partner interests in TEGP held by the Exchange Right Holders were converted into 115,729,440 Class B shares, 6,225,000 of which were automatically cancelled in connection with the underwriters’ exercise of its overallotment option; (iv) Tallgrass Equity issued 41,500,000 Tallgrass Equity units to TEGP in exchange for approximately $1.1 billion in net proceeds from the issuance of TEGP’s Class A shares to the public and amended the limited liability company agreement of Tallgrass Equity to, among other things, provide that TEGP is the managing member of Tallgrass Equity; (v) TEGP used the net proceeds from the purchase of the 6,225,000 overallotment option shares to purchase a like amount of Tallgrass Equity units from the Exchange Right Holders; and (vi) Tallgrass Equity entered into a $150 million revolving credit facility and borrowed $150 million thereunder, using the aggregate proceeds from such borrowings, together with the net proceeds from the Offering that Tallgrass Equity received from TEGP, to purchase 20 million TEP common units from Tallgrass Development, LP ("TD") at $47.68 per TEP common unit (the “Acquired TEP Units”) and pay offering expenses and other transaction costs. Tallgrass Equity distributed the remaining proceeds (the "Excess Proceeds") to the Exchange Right Holders. The following discussion analyzes the financial condition and results of operations of TEGP, which for periods prior to the completion of the Offering on May 12, 2015 includes the financial condition and results of operations of TEGP Predecessor, which refers to TEGP as recast to show the effects of the Reorganization Transactions.

In certain circumstances and for ease of reading we discuss the financial results of these entities prior to their respective acquisitions as being "our" financial results during historic periods, although Trailblazer Pipeline Company LLC ("Trailblazer") was owned by TD from November 13, 2012 to March 31, 2014, and Tallgrass Pony Express Pipeline, LLC ("Pony Express") was wholly-owned by TD from November 13, 2012 to August 31, 2014. As used in Item 2 of this Quarterly Report, unless the context otherwise requires, "we," "us," "our," the "Partnership," "TEGP" and similar terms refer to Tallgrass Energy GP, LP, together with its consolidated subsidiaries (including Tallgrass Equity, TEP and their respective subsidiaries). The term our "general partner" refers to TEGP Management, LLC. References to "TD" refer to Tallgrass Development, LP.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited condensed consolidated financial statements and related notes thereto included elsewhere in this Quarterly Report and the audited TEP financial statements and notes thereto, the related "Management's Discussion and Analysis of Financial Condition and Results of Operations," the discussion of "Risk Factors" and the discussion of TEGP's "Business" in our final prospectus dated May 6, 2015 (the “Prospectus”) and filed with the United States Securities and Exchange Commission (the “SEC”) on May 7, 2015.

A reference to a "Note" herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1.—Financial Statements. In addition, please read "Cautionary Statement Regarding Forward-Looking Statements" and "Risk Factors" for information regarding certain risks inherent in our business.

Cautionary Statement Regarding Forward-Looking Statements

This Quarterly Report and the documents incorporated by reference herein contain forward-looking statements concerning our operations, economic performance and financial condition. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as "could," "will," "may," "assume," "forecast," "position," "predict," "strategy," "expect," "intend," "plan," "estimate," "anticipate," "believe," "project," "budget," "potential," or "continue," and similar expressions are used to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this Quarterly Report include our expectations of plans, strategies, objectives, growth and anticipated financial and operational performance, including guidance regarding our and TD’s infrastructure programs, revenue projections, capital expenditures and tax position. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Quarterly Report. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:


•	our ability to complete and integrate acquisitions from TD or from third parties, including our acquisition of an additional 33.3% interest in Pony Express that was completed in March 2015;


•	changes in general economic conditions;


•	competitive conditions in our industry;


•	actions taken by third-party operators, processors and transporters;


•	the demand for natural gas transportation, storage and processing services and crude oil transportation services;


•	our ability to successfully implement our business plan;


•	our ability to complete internal growth projects on time and on budget;


•	the price and availability of debt and equity financing;


•	the availability and price of natural gas and crude oil, and fuels derived from both, to the consumer compared to the price of alternative and competing fuels;


•	competition from the same and alternative energy sources;


•	energy efficiency and technology trends;


•	operating hazards and other risks incidental to transporting crude oil and transporting, storing and processing natural gas;


•	natural disasters, weather-related delays, casualty losses and other matters beyond our control;


•	interest rates;


•	labor relations;


•	large customer defaults;


•	changes in tax status;


•	the effects of existing and future laws and governmental regulations;


•	the effects of future litigation; and


•	certain factors discussed elsewhere in this Quarterly Report.

Forward-looking statements speak only as of the date on which they are made. While we may update these statements from time to time, we are not required to do so other than pursuant to the securities laws.

Overview

TEGP is a Delaware limited partnership formed in 2015 that has elected to be treated as a corporation for U.S. federal income tax purposes. TEGP's only cash-generating assets consist of an approximately 30.35% controlling interest in Tallgrass Equity. Tallgrass Equity owns, through its ownership of TEP GP, all of TEP's IDRs and 834,391 TEP general partner units, representing an approximate 1.36% general partner interest in TEP as of September 30, 2015. Tallgrass Equity also directly owns the Acquired TEP Units, representing an approximate 32.57% limited partner interest in TEP as of September 30, 2015.

TEP is a publicly traded, growth-oriented limited partnership formed to own, operate, acquire and develop midstream energy assets in North America. We currently provide natural gas transportation and storage services for customers in the Rocky Mountain and Midwest regions of the United States through the Tallgrass Interstate Gas Transmission system, a FERC-regulated natural gas transportation and storage system located in Colorado, Kansas, Missouri, Nebraska and Wyoming (the “TIGT System”), and a FERC-regulated natural gas pipeline system extending from the Colorado and Wyoming border to Beatrice, Nebraska (the “Trailblazer Pipeline”). We provide crude oil transportation to customers in Wyoming, Colorado, and the surrounding regions through our membership interest in Pony Express, which owns a crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma (the “Pony Express System”). We also provide services for customers in Wyoming at the Casper and Douglas natural gas processing facilities and the West Frenchie Draw natural gas treating facility, or, collectively, the Midstream Facilities, and we provide water business services to customers in Colorado and Texas through BNN Water Solutions, LLC ("Water Solutions"). Our operations are strategically located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford and Bakken shale formations.

We intend to continue to leverage our relationship with TD and utilize the significant experience of our management team to execute our growth strategy of acquiring midstream assets from TD and third parties, increasing utilization of our existing assets and expanding our systems through construction of additional assets. Our reportable business segments are:


•	Natural Gas Transportation & Logistics—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities;


•	Crude Oil Transportation & Logistics—the ownership and operation of a crude oil pipeline system; and


•	Processing & Logistics—the ownership and operation of natural gas processing, treating and fractionation facilities, as well as water business services provided primarily to the oil and gas exploration and production industry.

Financial Presentation

TEGP has no operations outside of its indirect ownership interests in TEP. TEGP is the managing member of and therefore controls Tallgrass Equity. Tallgrass Equity, in turn, controls TEP through the direct ownership of 100% of TEP GP, TEP’s general partner. As a result, under generally accepted accounting principles, TEGP consolidates Tallgrass Equity, TEP GP, TEP, and TEP's subsidiaries. As such, TEGP's results of operations will not differ materially from the results of operations of TEP. The most noteworthy reconciling items between TEGP's condensed consolidated financial statements and TEP's condensed consolidated financial statements primarily relate to (i) the inclusion of the Tallgrass Equity revolving credit facility, (ii) the impact of TEGP's election to be treated as a corporation for U.S. federal income tax purposes and (iii) the presentation of noncontrolling interests in Tallgrass Equity and TEP. The interests in Tallgrass Equity and TEP that are not directly or indirectly owned by TEGP will be reflected as being attributable to noncontrolling interests in TEGP's condensed consolidated financial statements.

In addition, TEP’s historical results of operations do not reflect TEGP's incremental general and administrative costs associated with becoming a separate publicly traded entity, including expenses associated with (i) compensation for new directors, (ii) incremental director and officer liability insurance, (iii) listing on the NYSE, (iv) investor relations, (v) legal, (vi) tax and (vii) accounting.

Recent Developments

TEGP Distribution Declared

On October 5, 2015, the Board of Directors of our general partner declared a cash distribution for the quarter ended September 30, 2015 of $0.144 per Class A share. The distribution will be paid on November 13, 2015, to Class A shareholders of record on October 30, 2015.

TEP Distribution Declared

On October 5, 2015, the Board of Directors of TEP's general partner declared a cash distribution for the quarter ended September 30, 2015 of $0.60 per common unit. The distribution will be paid on November 13, 2015, to unitholders of record on October 30, 2015.

U.S. Crude Oil and Natural Gas Supply and Demand Dynamics

Crude oil, natural gas and products derived from both continue to be critical components of energy supply and demand in the United States. Although crude oil and natural gas prices have declined in the latter part of 2014 and into 2015, and may remain at or near current levels for the foreseeable future, we believe that the long-term prospects for continued crude oil and natural gas production increases are favorable and will be driven in part by increased domestic demand resulting from population and economic growth, higher industrial consumption in the U.S. and a desire to reduce domestic reliance on imports. We expect natural gas to continue to displace coal-fired electricity generation due to the low prices of natural gas and stricter environmental regulations on the mining and burning of coal. For additional information, please read Item 3. – Quantitative and Qualitative Disclosures About Market Risk.

How We Evaluate Our Operations

We evaluate our results using, among other measures, cash distributions received from Tallgrass Equity, TEP's contract profile and volumes, and operating costs and expenses of TEGP and its consolidated subsidiaries.

Cash Distributions Received from Tallgrass Equity

TEGP's cash flow is currently generated solely by distributions received from Tallgrass Equity. Tallgrass Equity currently receives all of its cash flows from distributions on its direct and indirect partnership interests in TEP. Tallgrass Equity is therefore entirely dependent upon the ability of TEP to make cash distributions to its partners.

TEP's Contract Profile and Volumes

Our results are driven primarily by the volume of crude oil transportation capacity under firm contracts, the volume of natural gas transportation and storage capacity under firm contracts, the volume of natural gas that we process and the fees assessed for such services.

Operating Costs and Expenses

The primary components of our operating costs and expenses that we evaluate include cost of sales, cost of transportation services, operations and maintenance and general and administrative costs. Our operating expenses are driven primarily by expenses related to the operation, maintenance and growth of our asset base.

Results of Operations

The following provides a summary of our consolidated results of operations for the periods indicated:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(in thousands, except operating data)
Revenues:
Sales of natural gas, NGLs, and crude oil	$	20,252		$	49,130		$	62,132		$	141,887
Natural gas transportation services	29,431			30,745			90,620			95,418
Crude oil transportation services	81,928			—			206,331			—
Processing and other revenues	6,557			10,078			26,730			24,747
Total Revenues	138,168			89,953			385,813			262,052
Operating Costs and Expenses:
Cost of sales	18,186			45,767			54,959			131,187
Cost of transportation services	14,862			3,329			39,069			13,734
Operations and maintenance	14,071			9,961			36,054			28,029
Depreciation and amortization	20,802			10,071			61,762			27,905
General and administrative	12,321			7,448			38,711			21,221
Taxes, other than income taxes	5,521			1,797			16,547			5,392
Loss on sale of assets	—			—			4,483			—
Total Operating Costs and Expenses	85,763			78,373			251,585			227,468
Operating Income	52,405			11,580			134,228			34,584
Other (Expense) Income:
Interest expense, net	(4,982		)	(1,058		)	(12,901		)	(4,492		)
Gain on remeasurement of unconsolidated investment	—			—			—			9,388
Equity in earnings of unconsolidated investment	—			—			—			717
Other income, net	502			731			1,983			2,400
Total Other (Expense) Income	(4,480		)	(327		)	(10,918		)	8,013
Net income before tax	47,925			11,253			123,310			42,597
Deferred income tax expense	(1,828		)	—			(3,600		)	—
Net income	46,097			11,253			119,710			42,597
less: Net income attributable to noncontrolling interests	(41,674		)	(9,623		)	(105,431		)	(35,897		)
Net income attributable to TEGP	$	4,423		$	1,630		$	14,279		$	6,700
Operating Data:
Gas transportation firm contracted capacity (MMcf/d)	1,506			1,497			1,543			1,532
Crude oil transportation average throughput (Bbls/d)	252,540			N/A			218,697			N/A
Natural gas processing inlet volumes (MMcf/d)	110			153			128			147

Three Months Ended September 30, 2015 Compared to the Three Months Ended September 30, 2014

Revenues. Total revenues were $138.2 million for the three months ended September 30, 2015, compared to $90.0 million for the three months ended September 30, 2014, which represents an increase of $48.2 million, or 54%, in total revenues. The overall increase in revenue was largely driven by revenues of $83.3 million in the Crude Oil Transportation & Logistics segment for the three months ended September 30, 2015. There were no revenues in that segment for the three months ended September 30, 2014 as Pony Express had not yet commenced commercial operations. The Crude Oil Transportation & Logistics segment revenue was partially offset by a decrease in revenues of $35.3 million in the Processing & Logistics segment as discussed further below.

Operating costs and expenses. Operating costs and expenses were $85.8 million for the three months ended September 30, 2015 compared to $78.4 million for the three months ended September 30, 2014, which represents an increase of $7.4 million, or 9%. The increase in operating costs and expenses is primarily driven by operating costs and expenses of $39.2 million in the Crude Oil Transportation & Logistics segment, reflecting the commencement of commercial operations at Pony Express, partially offset by a decrease in operating costs and expenses of $29.9 million in the Processing & Logistics segment as discussed further below.

Interest expense, net. Interest expense of $5.0 million and $1.1 million for the three months ended September 30, 2015 and 2014, respectively, was primarily composed of interest and fees associated with TEP’s revolving credit facility. Interest expense for the three months ended September 30, 2015 also includes interest and fees associated with Tallgrass Equity's revolving credit facility. The increase in interest and fees associated with TEP's revolving credit facility is primarily due to increased borrowings during the three months ended September 30, 2015 to fund a portion of our recent acquisitions.

Other income, net. Other income, net typically includes rental income, income earned from certain customers related to the capital costs we incurred to connect these customers to our system, the allowance for funds used during construction at our regulated entities, and other noncash gains and losses. Other income for the three months ended September 30, 2015 was $0.5 million compared to $0.7 million for the three months ended September 30, 2014.

Deferred income tax expense. Deferred income tax expense for the three months ended September 30, 2015 was $1.8 million, and represents tax expense related to our income for the three months ended September 30, 2015.

Nine Months Ended September 30, 2015 Compared to the Nine Months Ended September 30, 2014

Revenues. Total revenues were $385.8 million for the nine months ended September 30, 2015, compared to $262.1 million for the nine months ended September 30, 2014, which represents an increase of $123.8 million, or 47%, in total revenues. The overall increase in revenues was largely driven by revenues of $208.9 million in the Crude Oil Transportation & Logistics segment for the nine months ended September 30, 2015. There were no revenues in that segment for the nine months ended September 30, 2014 as Pony Express had not yet commenced commercial operations. The Crude Oil Transportation & Logistics segment revenue was partially offset by decreases in revenues of $76.2 million and $8.9 million in the Processing & Logistics and Natural Gas Transportation & Logistics segments, respectively, as discussed further below.

Operating costs and expenses. Operating costs and expenses were $251.6 million for the nine months ended September 30, 2015 compared to $227.5 million for the nine months ended September 30, 2014, which represents an increase of $24.1 million, or 11%. The overall increase in operating costs and expenses is primarily driven by increased operating costs and expenses of $102.7 million at Pony Express, reflecting the commencement of commercial operations at Pony Express, partially offset by decreases in operating costs and expenses of $66.3 million and $9.8 million in the Processing & Logistics and Natural Gas Transportation & Logistics segments, respectively, as discussed further below.

Interest expense, net. Interest expense of $12.9 million for the nine months ended September 30, 2015 was primarily composed of interest and fees associated with TEP’s and Tallgrass Equity's revolving credit facilities, partially offset by interest income of $0.4 million on the cash balance swept to TD under the Pony Express cash management agreement. Interest expense of $4.5 million for the nine months ended September 30, 2014 was primarily composed of interest and fees associated with TEP’s revolving credit facility, partially offset by interest income of $0.5 million on the cash balance swept to TD under the Pony Express cash management agreement. The increase in interest and fees is primarily due to increased borrowings during the nine months ended September 30, 2015 to fund a portion of our recent acquisitions.

Gain on remeasurement of unconsolidated investment. Gain on remeasurement of unconsolidated investment of $9.4 million for the nine months ended September 30, 2014 was related to the remeasurement to fair value of our original 50% equity investment in Grasslands Water Services I, LLC (“GWSI”) in connection with TEP's consolidation of the Water Solutions business on May 13, 2014.

Equity in earnings of unconsolidated investment. Equity in earnings of unconsolidated investment of $0.7 million for the nine months ended September 30, 2014 was related to our investment in GWSI prior to TEP's consolidation of the Water Solutions business on May 13, 2014.

Other income, net. Other income, net typically includes rental income, income earned from certain customers related to the capital costs we incurred to connect these customers to our system, the allowance for funds used during construction at our regulated entities, and other noncash gains and losses. Other income for the nine months ended September 30, 2015 was $2.0 million compared to $2.4 million for the nine months ended September 30, 2014.

Deferred income tax expense. Deferred income tax expense for the nine months ended September 30, 2015 was $3.6 million, and represents tax expense related to our income for the period from May 12, 2015 to September 30, 2015.

The following provides a summary of our Natural Gas Transportation & Logistics segment results of operations for the periods indicated:



Segment Financial Data - Natural Gas Transportation & Logistics⁽¹⁾	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(in thousands)
Revenues:
Sales of natural gas, NGLs, and crude oil	$	2,855	$	1,302	$	3,534	$	7,440
Natural gas transportation services	30,777		32,175		94,656		99,433
Processing and other revenues	4		43		25		218
Total revenues	33,636		33,520		98,215		107,091
Operating costs and expenses:
Cost of sales	2,565		911		2,436		6,584
Cost of transportation services	2,808		3,186		8,918		13,568
Operations and maintenance	7,263		6,699		20,362		19,396
Depreciation and amortization	5,241		6,025		17,066		17,745
General and administrative	4,104		4,191		12,789		12,574
Taxes, other than income taxes	1,156		1,717		3,655		5,149
Total operating costs and expenses	23,137		22,729		65,226		75,016
Operating income	$	10,499	$	10,791	$	32,989	$	32,075


⁽¹⁾	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 15 – Reporting Segments to the accompanying condensed consolidated financial statements.

Three Months Ended September 30, 2015 Compared to the Three Months Ended September 30, 2014

Revenues. Natural Gas Transportation & Logistics segment revenues were $33.6 million for the three months ended September 30, 2015, compared to $33.5 million for the three months ended September 30, 2014, which represents a $0.1 million increase in segment revenues primarily driven by a $1.6 million increase in sales of natural gas, NGLs, and crude oil driven by increased volumes of natural gas sold, partially offset by a 39% decrease in natural gas prices. The increase in sales of natural gas, NGLs, and crude oil was partially offset by a $1.4 million decrease in natural gas transportation services primarily driven by decreased prices on fuel reimbursements.

Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation & Logistics segment were $23.1 million for the three months ended September 30, 2015 compared to $22.7 million for the three months ended September 30, 2014, which represents an increase of $0.4 million, or 2%. The overall increase in operating costs and expenses was primarily driven by a $1.7 million increase in cost of sales, driven by increased volumes of natural gas sold, partially offset by a 26% decrease in natural gas prices, and a $0.6 million increase in operations and maintenance costs, partially offset by a $0.8 million decrease in depreciation and amortization, a $0.6 million decrease in taxes, other than income taxes, a $0.4 million decrease in the cost of transportation services, and a $0.1 million decrease in general and administrative costs.

Nine Months Ended September 30, 2015 Compared to the Nine Months Ended September 30, 2014

Revenues. Natural Gas Transportation & Logistics segment revenues were $98.2 million for the nine months ended September 30, 2015, compared to $107.1 million for the nine months ended September 30, 2014, which represents a $8.9 million, or 8%, decrease in segment revenues primarily driven by a $4.8 million decrease in natural gas transportation services revenue driven by decreased prices on fuel reimbursements, and a $3.9 million decrease in revenue from the sales of natural gas, NGLs, and crude oil as a result of a 43% decrease in natural gas prices, partially offset by increased volumes sold.

Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation & Logistics segment were $65.2 million for the nine months ended September 30, 2015 compared to $75.0 million for the nine months ended September 30, 2014, which represents a decrease of $9.8 million, or 13%. The overall decrease in operating costs and expenses was primarily driven by a $4.7 million decrease in the cost of transportation services, due to lower fuel reimbursements as a result of decreased prices, a $4.1 million decrease in cost of sales, due to a 26% decrease in natural gas prices and a reduction in our fuel tracker obligations at Trailblazer driven by the FERC approval of our annual fuel tracker filing, partially offset by increased volumes of natural gas sold, and a $1.5 million decrease in taxes, other than income taxes, due to revised property tax estimates as a result of successful appeals with state taxing authorities on the assessed value of property. These decreases were partially offset by a $1.0 million increase in operations and maintenance costs due to increased pipeline integrity work during the nine months ended September 30, 2015.

The following provides a summary of our Crude Oil Transportation & Logistics segment results of operations for the periods indicated:



Segment Financial Data - Crude Oil Transportation & Logistics ⁽¹⁾	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015		2014
	(in thousands)
Revenues:
Sales of natural gas, NGLs, and crude oil	$	1,344	$	—		$	2,541	$	—
Crude Oil transportation services	81,928		—			206,331		—
Total revenues	83,272		—			208,872		—
Operating costs and expenses:
Cost of sales	1,482		—			2,468		—
Cost of transportation services	13,393		—			33,630		—
Operations and maintenance	2,657		—			6,087		—
Depreciation and amortization	12,257		757			34,791		2,271
General and administrative	5,155		65			15,465		65
Taxes, other than income taxes	4,259		—			12,574		—
Total operating costs and expenses	39,203		822			105,015		2,336
Operating income (loss)	$	44,069	$	(822	)	$	103,857	$	(2,336	)


⁽¹⁾	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 15 – Reporting Segments to the accompanying condensed consolidated financial statements.

Three Months Ended September 30, 2015 Compared to the Three Months Ended September 30, 2014

Revenues. Crude Oil Transportation & Logistics segment revenues of $83.3 million for the three months ended September 30, 2015 represents transportation revenue at Pony Express, which was placed in service in October 2014, and commercial operations at the lateral in Northeast Colorado, which commenced during the second quarter of 2015. There were no revenues for the three months ended September 30, 2014 as Pony Express had not yet commenced commercial operations.

Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation & Logistics segment were $39.2 million for the three months ended September 30, 2015 compared to $0.8 million for the three months ended September 30, 2014. Operating costs and expenses for the three months ended September 30, 2015 include costs associated with commercial operations at Pony Express, which began in October 2014, and commercial operations at the lateral in Northeast Colorado, which began during the second quarter of 2015, as well as the amortization of the Pony Express oil conversion use rights. For the three months ended September 30, 2014, operating costs and expenses primarily consisted of the amortization of the Pony Express oil conversion use rights.

Nine Months Ended September 30, 2015 Compared to the Nine Months Ended September 30, 2014

Revenues. Crude Oil Transportation & Logistics segment revenues of $208.9 million for the nine months ended September 30, 2015 represents transportation revenue at Pony Express, which was placed in service in October 2014, and commercial operations at the lateral in Northeast Colorado, which commenced during the second quarter of 2015. There were no revenues for the nine months ended September 30, 2014 as Pony Express had not yet commenced commercial operations.

Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation & Logistics segment were $105.0 million for the nine months ended September 30, 2015 compared to $2.3 million for the nine months ended September 30, 2014. Operating costs and expenses for the nine months ended September 30, 2015 include costs associated with commercial operations at Pony Express, which began in October 2014, and commercial operations at the lateral in Northeast Colorado, which began during the second quarter of 2015, as well as the amortization of the Pony Express oil conversion use rights. For the nine months ended September 30, 2014, operating costs and expenses primarily consisted of the amortization of the Pony Express oil conversion use rights.

The following provides a summary of our Processing & Logistics segment results of operations for the periods indicated:



Segment Financial Data - Processing & Logistics ⁽¹⁾	Three Months Ended September 30,					Nine Months Ended September 30,
Segment Financial Data - Processing & Logistics ⁽¹⁾	2015			2014		2015		2014
	(in thousands)
Revenues:
Sales of natural gas, NGLs, and crude oil	$	16,053		$	47,828	$	56,057	$	134,447
Processing and other revenues	6,553			10,035		26,705		24,529
Total revenues	22,606			57,863		82,762		158,976
Operating costs and expenses:
Cost of sales	14,139			44,856		50,055		124,603
Cost of transportation services	7			143		557		166
Operations and maintenance	4,151			3,262		9,605		8,633
Depreciation and amortization	3,304			3,289		9,905		7,889
General and administrative	1,111			1,092		3,331		2,983
Taxes, other than income taxes	106			80		318		243
Loss on sale of assets	—			—		4,483		—
Total operating costs and expenses	22,818			52,722		78,254		144,517
Operating (loss) income	$	(212	)	$	5,141	$	4,508	$	14,459


⁽¹⁾	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 15 – Reporting Segments to the accompanying condensed consolidated financial statements.

Three Months Ended September 30, 2015 Compared to the Three Months Ended September 30, 2014

Revenues. Processing & Logistics segment revenues were $22.6 million for the three months ended September 30, 2015, compared to $57.9 million for the three months ended September 30, 2014, which represents a $35.3 million, or 61%, decrease in segment revenues. The decrease in segment revenues was primarily due to a $31.8 million decrease in sales of natural gas, NGLs, and crude oil driven by a 62% decrease in NGL prices and lower volumes processed during the period, and a $3.5 million decrease in processing and other revenues primarily due to decreased volumes processed under a large, fee-based contract.

Operating costs and expenses. Operating costs and expenses in the Processing & Logistics segment were $22.8 million for the three months ended September 30, 2015 compared to $52.7 million for the three months ended September 30, 2014, which represents a decrease of $29.9 million, or 57%. The decrease was primarily driven by a $30.7 million, or 68%, decrease in cost of sales, partially offset by a $0.9 million increase in operations and maintenance costs. The decrease in cost of sales in the three months ended September 30, 2015 when compared to the same period in the prior year was primarily driven by decreased NGL prices and lower volumes processed as discussed above. Operations and maintenance costs increased $0.9 million, or 27%, in the three months ended September 30, 2015 when compared to the same period in the prior year, primarily driven by costs associated with annual plant maintenance activities during the three months ended September 30, 2015 which occurred during the second quarter in 2014.

Nine Months Ended September 30, 2015 Compared to the Nine Months Ended September 30, 2014

Revenues. Processing & Logistics segment revenues were $82.8 million for the nine months ended September 30, 2015, compared to $159.0 million for the nine months ended September 30, 2014, which represents a $76.2 million, or 48%, decrease in segment revenues. The decrease in segment revenues was primarily due to a $78.4 million decrease in the sales of natural gas, NGLs, and crude oil driven by a 61% decrease in NGL prices and lower volumes processed, partially offset by an increase in volumes of trucked NGLs sold. The decrease in sales of natural gas, NGLs, and crude oil was partially offset by a $2.2 million increase in processing and other revenues driven by increased revenue at Water Solutions, including water transportation services and revenue associated with a third party pipeline construction project during the nine months ended September 30, 2015, partially offset by lower processing fees at TMID due to decreased volumes processed under a large, fee-based contract. Prior to its consolidation in May 2014, TEP's investment in Water Solutions was accounted for under the equity method of accounting and as a result TEP recognized no revenues from Water Solutions for the period from January 1, 2014 to May 13, 2014.

Operating costs and expenses. Operating costs and expenses in the Processing & Logistics segment were $78.3 million for the nine months ended September 30, 2015 compared to $144.5 million for the nine months ended September 30, 2014, which represents a decrease of $66.3 million, or 46%. The decrease in operating costs and expenses was driven by a decrease of $74.5 million in cost of sales, primarily driven by decreased NGL prices and processed volumes as discussed above, partially offset by an increase in volumes of trucked NGLs sold. The decrease in cost of sales was partially offset by the $4.5 million non-cash loss recognized on the sale of compressor assets during the nine months ended September 30, 2015, and overall increases in the cost of transportation services, operations and maintenance costs, depreciation and amortization, and general and administrative costs primarily driven by the costs associated with Water Solutions, which was consolidated in May 2014.

Liquidity and Capital Resources Overview

We expect our primary sources of liquidity on a consolidated basis to include cash generated from our operations, borrowing capacity available under TEP's and Tallgrass Equity's revolving credit facilities, and future issuances of equity and/or debt securities.

We believe that cash on hand, cash generated from operations, and availability under TEP’s and Tallgrass Equity's revolving credit facility will be adequate to meet our operating needs, our planned short-term capital and debt service requirements, and our planned cash distributions to shareholders. We believe that future internal growth projects or potential acquisitions will be funded primarily through a combination of borrowings under TEP's revolving credit facility and issuance of debt and/or equity securities.

Our total liquidity as of September 30, 2015 and December 31, 2014 was as follows:



	September 30, 2015			December 31, 2014
	(in thousands)
Cash on hand⁽¹⁾	$	19,009		$	867

Total capacity under the TEP revolving credit facility	850,000			850,000
Less: Outstanding borrowings under the TEP revolving credit facility	(696,000		)	(559,000		)
Available capacity under the TEP revolving credit facility	154,000			291,000
Total capacity under the Tallgrass Equity revolving credit facility	$	150,000		$	—
Less: Outstanding borrowings under the Tallgrass Equity revolving credit facility	(148,000		)	—
Available capacity under the Tallgrass Equity revolving credit facility	$	2,000		$	—
Total Liquidity	$	175,009		$	291,867


⁽¹⁾	Includes $17.5 million of cash retained at Pony Express as of September 30, 2015 to fund working capital obligations.

TEP Revolving Credit Facility

The unused portion of TEP's revolving credit facility is subject to a commitment fee, which ranges from 0.300% to 0.500%, based on TEP’s total leverage ratio. As of September 30, 2015, the weighted average interest rate on outstanding borrowings was 1.97%.

Tallgrass Equity Revolving Credit Facility

In connection with the Offering, Tallgrass Equity entered into a new $150 million senior secured revolving credit facility with Barclays Bank PLC, as administrative agent, and a syndicate of lenders, which will mature on May 12, 2020. The Tallgrass Equity credit facility includes a $10 million sublimit for letters of credit and a $10 million sublimit for swing line loans. The Tallgrass Equity revolving credit facility may be used (i) to pay transaction costs and any fees and expenses incurred in connection with the revolving credit facility and certain transactions relating to the Offering, (ii) to fund the purchase of the Acquired TEP Units and (iii) for general company purposes, including distributions. The Tallgrass Equity revolving credit facility also contains an accordion feature whereby Tallgrass Equity can increase the size of the credit facility to an aggregate of $200 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions precedent. In addition, Tallgrass Equity is required to maintain a total leverage ratio of not more than 3.00 to 1.00. As of September 30, 2015, Tallgrass Equity was in compliance with the covenants required under the revolving credit facility.

The unused portion of the revolving credit facility is subject to a commitment fee of 0.50% per annum on the daily unused amount of the revolving credit commitment reduced by the face amount of the letters of credit issued and outstanding. As of September 30, 2015, the weighted average interest rate on outstanding borrowings was 2.71%.

TEP Public Offering

Working Capital

Working capital is the amount by which current assets exceed current liabilities. While various other factors may impact our working capital requirements from period to period, our working capital requirements have typically been, and we expect will continue to be, driven by changes in accounts receivable and accounts payable. Factors impacting changes in accounts receivable and accounts payable could include the timing of collections from customers, payments to suppliers, as well as the level of spending for capital expenditures and changes in the market prices of energy commodities that we buy and sell in the normal course of business.

As of September 30, 2015, we had a working capital surplus of $16.0 million compared to a working capital surplus of $35.7 million at December 31, 2014, which represents a decrease in working capital of $19.7 million. The overall decrease in working capital was primarily attributable to a decrease of $73.4 million in receivables from related parties due to the utilization of the Pony Express cash balance swept to TD under the cash management agreement, an increase in deferred revenue of $14.3 million, and an increase in accrued taxes of $12.6 million. These working capital decreases were partially offset by a decrease of $42.7 million in accounts payable, primarily driven by the timing of project invoices and payment of contractor retainages related to the construction of the Pony Express lateral in Northeast Colorado placed in service in April 2015 and lower producer settlements at TMID, an increase in accounts receivable driven by the start of commercial operations at the Pony Express lateral in Northeast Colorado and the activation of the Hiland Pipeline Company joint tariff at Pony Express, and an increase in cash of $17.8 million primarily due to cash balances retained at Pony Express at September 30, 2015 to fund working capital obligations.

A material adverse change in operations, available financing under our revolving credit facility, or available financing from the equity or debt capital markets could impact our ability to fund our requirements for liquidity and capital resources in the future.

Cash Flows

The following table and discussion presents a summary of our cash flow for the periods indicated:



	Nine Months Ended September 30,
	2015			2014
	(in thousands)
Net cash provided by (used in):
Operating activities	$	195,447		$	47,244
Investing activities	$	(769,771	)	$	(1,099,084	)
Financing activities	$	592,466		$	1,052,725

Nine Months Ended September 30, 2015 Compared to the Nine Months Ended September 30, 2014

Operating Activities. Cash flows provided by operating activities were $195.4 million and $47.2 million for the nine months ended September 30, 2015 and 2014, respectively. The increase in net cash flows provided by operating activities of $148.2 million was primarily driven by the increase in operating results and a net increase in cash inflows from changes in working capital, primarily driven by a $21.9 million decrease in net cash outflows from accounts payable and accrued liabilities due to increased property tax accruals and operating payables and a $12.5 million increase in net cash inflows from deficiency payments received by Pony Express, partially offset by a decrease in net cash inflows of $14.1 million from accounts receivable, due to increased receivables at Pony Express.

Investing Activities. Cash flows used in investing activities were $769.8 million and $1.1 billion for the nine months ended September 30, 2015 and 2014, respectively. During the nine months ended September 30, 2015, net cash used in investing activities were driven by the $700.0 million cash outflow for the acquisition of an additional 33.3% membership interest in Pony Express, which allowed TD to continue funding the pipeline construction at Pony Express, and capital expenditures of $65.1 million, primarily due to construction of the Pony Express System, including the lateral in Northeast Colorado. During the nine months ended September 30, 2014, net cash used in investing activities was driven by $642.2 million in capital expenditures, consisting primarily of spending on the conversion and construction of the Pony Express System, the $270.0 million in cash swept to TD under the Pony Express cash management agreement, as discussed in Note 4 – Acquisitions, and cash outflows of $150.0 million, $27.0 million, and $7.6 million, respectively, for the acquisition of Trailblazer effective April 1, 2014, the acquisition of a 33.3% membership interest in Pony Express effective September 1, 2014, and the acquisition of an additional equity interest in Water Solutions effective May 13, 2014.

Financing Activities. Cash flows provided by financing activities were $592.5 million and $1.1 billion for the nine months ended September 30, 2015 and 2014, respectively. Cash flows provided by financing activities for the nine months ended September 30, 2015 were primarily driven by $1.3 billion of net proceeds from the initial public offering of Class A shares in May 2015, $551.2 million of net proceeds from the public offering of TEP common units in February 2015, the proceeds from net borrowings under the TEP and Tallgrass Equity revolvers of $285.0 million, and contributions from noncontrolling interests of $19.3 million primarily driven by contributions from TD to Pony Express. These proceeds were partially offset by cash outflows of $953.6 million for the acquisition of the Acquired TEP Units, the $334.1 million distribution of the Excess Proceeds from the initial public offering of Class A shares to the Exchange Right Holders, and cash outflows of $171.9 million for the acquisition of additional Tallgrass Equity units, all as part of the Reorganization Transactions, distributions to TEP unitholders of $74.8 million, distributions to the members of the TEGP Predecessor of $13.5 million, distributions made by Tallgrass Equity to the Exchange Right Holders of $13.0 million, and distributions to TEGP shareholders of $3.5 million.

Cash flows provided by financing activities for the nine months ended September 30, 2014 consisted primarily of proceeds from net borrowings under the TEP revolver of $433.0 million, proceeds from TEP's public offering of common units in July 2014 of $319.6 million, net contributions from the members of the TEGP Predecessor of $289.4 million, and a $27.5 million contribution from TD representing the difference between the carrying amount of the Replacement Gas Facilities, as discussed in Note 14 – Regulatory Matters, and the proceeds received from TD. These financing cash inflows were partially offset by distributions to TEP unitholders of $23.8 million.

Distributions

Distributions to our Class A shareholders. We distribute 100% of our available cash at the end of each quarter to Class A shareholders of record beginning with the quarter ended June 30, 2015. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements. Our distribution for the three months ended September 30, 2015, in the amount of $0.144 per Class A share, or $6.9 million in the aggregate, was declared on October 5, 2015 and is payable on November 13, 2015 to Class A shareholders of record on October 30, 2015.

Capital Requirements

The midstream energy business can be capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to consist of the following:


•	maintenance capital expenditures, which are cash expenditures incurred (including expenditures for the construction or development of new capital assets) that we expect to maintain our long-term operating income or operating capacity. These expenditures typically include certain system integrity, compliance and safety improvements; and


•	expansion capital expenditures, which are cash expenditures to increase our operating income or operating capacity over the long term. Expansion capital expenditures include acquisitions or capital improvements (such as additions to or improvements on the capital assets owned, or acquisition or construction of new capital assets).

We expect to incur approximately $209 million for capital expenditures in 2015, of which approximately $176 million is expected for the construction of the lateral to the Pony Express System located in Northeast Colorado and remaining costs associated with completion of the construction of the Pony Express System, approximately $20 million is expected for other expansion projects, and approximately $13 million is expected for maintenance capital expenditures.

The determination of capital expenditures as maintenance or expansion is made at the individual asset level during our budgeting process and as we approve, execute, and monitor our capital spending. The following table summarizes the maintenance and expansion capital expenditures incurred at our consolidated entities:



	Nine Months Ended September 30,
	2015		2014
	(in thousands)
Maintenance capital expenditures	$	9,237	$	7,654
Expansion capital expenditures	137,707		669,944
Total capital expenditures incurred	$	146,944	$	677,598

Capital expenditures incurred represent capital expenditures paid and accrued during the period, inclusive of Pony Express capital expenditures paid by TD on behalf of Pony Express and settled via the cash management agreement. The increase in maintenance capital expenditures to $9.2 million for the nine months ended September 30, 2015 from $7.7 million for the nine months ended September 30, 2014 is primarily driven by increased maintenance capital expenditures in the Natural Gas Transportation & Logistics and Processing & Logistics segments. Maintenance capital expenditures on our assets occur on a regular schedule, but most major maintenance projects are not required every year so the level of maintenance capital expenditures naturally varies from year to year and from quarter to quarter. The decrease in expansion capital expenditures to $137.7 million for the nine months ended September 30, 2015 from $669.9 million for the nine months ended September 30, 2014 is primarily driven by the significant spending on the Pony Express System prior to commencement of commercial operations in October 2014. Expansion capital expenditures of $137.7 million for the nine months ended September 30, 2015 consisted primarily of spending on the Pony Express System lateral in Northeast Colorado.

In addition, we invested cash in unconsolidated affiliates of $2.0 million during the nine months ended September 30, 2014 to fund our share of capital expansion projects. There were no investments in unconsolidated affiliates during the nine months ended September 30, 2015.

We intend to make cash distributions to our Class A shareholders. Due to our cash distribution policy, we expect that we will distribute available cash to our Class A shareholders on a quarterly basis. We expect TEP to fund future capital expenditures with funds generated from its operations, borrowings under its revolving credit facility, the issuance of additional partnership units and/or the issuance of long-term debt. If these sources are not sufficient, TEP may reduce its discretionary spending.

Contractual Obligations

There have been no material changes in our contractual obligations as reported in the Prospectus.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Critical Accounting Policies and Estimates

TEGP’s significant accounting policies are described in Note 2 – Summary of Significant Accounting Policies to the condensed consolidated financial statements. Management’s discussion and analysis of financial condition and results of operations are based upon TEGP’s financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosure of contingent assets and liabilities. The accounting policies discussed in the "Critical Accounting Policies and Estimates" section of our Prospectus, as well as the policy discussed below, are considered by management to be critical to an understanding of TEGP’s financial statements as their application places the most significant demands on management’s judgment. Due to the inherent uncertainties involved with this type of judgment, actual results could differ significantly from estimates and may have a material adverse impact on TEGP’s results of operations, equity or cash flows. For additional information concerning TEGP’s other accounting policies, please read the notes to TEGP’s condensed consolidated financial statements.



Description	Judgments and Uncertainties	Effect if Actual Results Differ from Assumptions
Income Taxes
Current income tax expense is the amount of income taxes expected to be payable for the current year. A deferred income tax liability or asset is established for the expected future tax consequences resulting from the differences in financial reporting and tax bases of assets and liabilities. Each quarter we evaluate the reasonableness of the deferred tax assets and a valuation allowance is provided if it is more likely than not that some or all of the deferred tax assets will not be realized.	Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements, which will result in taxable or deductible amounts in the future. In evaluating our ability to recover our deferred tax assets we consider all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies, and results of recent operations. In projecting future taxable income, we begin with historical results adjusted for the results of discontinued operations and incorporate assumptions about the amount of future state and federal pretax operating income adjusted for items that do not have tax consequences. The assumptions about future taxable income require the use of significant judgment and are consistent with the plans and estimates we are using to manage the underlying businesses.	In the instance that the valuation allowance does not appropriately adjust our deferred tax assets to reflect the actual future tax benefits or consequences from the differences between the tax basis of assets and liabilities and their reported amounts in the financial statements include the following: our balance sheet may be overstated or understated resulting in an overstated or understated Income Tax Expense on the Income Statement resulting in either understated or overstated Net Income after Income Tax.

Other than the aforementioned new accounting policy regarding income taxes, which was adopted upon our election to be treated as a corporation for U.S. federal income tax purposes on the effective date of the closing of the Offering, there have been no significant changes in the application of critical accounting policies and estimates since the filing of our Prospectus.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

The profitability of our processing contracts that include keep whole or percent of proceeds components is affected by volatility in prevailing NGL and natural gas prices. As of September 30, 2015 approximately 90% of our reserved processing capacity was subject to fee-based processing contracts, with the remaining 10% subject to percent of proceeds or keep whole processing contracts. We do not currently hedge the commodity exposure in our processing contracts and we do not expect to in the foreseeable future. Our Processing & Logistics segment comprised less than 1% and approximately 3% of our operating income for the three and nine months ended September 30, 2015, respectively.

We have a limited amount of direct commodity price exposure related to crude oil collected as part of our contractual pipeline loss allowance at Pony Express. We do not currently hedge this commodity exposure.

We also have a limited amount of direct commodity price exposure related to natural gas collected related to electrical compression costs and lost and unaccounted for gas on the TIGT System. Historically, we have entered into derivative contracts with third parties for a substantial majority of the gas we expect to collect during the current year for the purpose of hedging our commodity price exposures. We expect to continue these hedging activities for the foreseeable future. As of September 30, 2015, we had natural gas swaps outstanding with a notional volume of approximately 0.6 Bcf short, representing a portion of the natural gas that is expected to be sold by our Natural Gas Transportation & Logistics segment through the end of 2015. The fair value of these swaps was an asset of approximately $218,000 at September 30, 2015.

We measure the risk of price changes in our natural gas swaps utilizing a sensitivity analysis model. The sensitivity analysis measures the potential income or loss (i.e., the change in fair value of the derivative instruments) based upon a hypothetical 10% movement in the underlying quoted market prices. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. We enter into derivative contracts solely for the purpose of mitigating the risks that accompany certain of our business activities and, therefore, both the sensitivity analysis model and the change in the market value of our outstanding derivative contracts are offset largely by changes in the value of the underlying physical natural gas sales. A hypothetical 10% increase in the natural gas price forward curve would result in a decrease of approximately $0.2 million in the net fair value of our derivative instruments for the quarter ended September 30, 2015 as a result of our hedging program. For the purpose of determining the change in fair value associated with the hypothetical natural gas price increase scenario, we have assumed a parallel shift in the forward curve through the end of 2015.

The Commodity Futures Trading Commission ("CFTC") has promulgated regulations to implement Dodd-Frank’s changes to the Commodity Exchange Act, including the definition of commodity-based swaps subject to those regulations. The CFTC regulations are intended to implement new reporting and record keeping requirements related to those swap transactions and a mandatory clearing and exchange-execution regime for various types, categories or classes of swaps, subject to certain exemptions, including the trade-option and end-user exemptions. Although we anticipate that most, if not all, of our swap transactions should qualify for an exemption to the clearing and exchange-execution requirements, we will still be subject to record keeping and reporting requirements. Other changes to the Commodity Exchange Act made as a result of the Dodd-Frank Act and the CFTC’s implementing regulations could significantly increase the cost of entering into new swaps.

Interest Rate Risk

As described in "Liquidity and Capital Resources Overview" above, TEP currently has an $850 million revolving credit facility. Borrowings under the revolving credit facility will bear interest, at our option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar Rate, plus, in each case, an applicable margin. For loans bearing interest based on the base rate, the applicable margin was initially 1.00%, and for loans bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin was initially 2.00%. After June 25, 2014, the applicable margin ranges from 0.75% to 2.75%, based upon our total leverage ratio and whether we have elected the base rate or the reserve adjusted Eurodollar rate.

As described in "Liquidity and Capital Resources Overview" above, TEGP currently has an additional $148 million in outstanding borrowings under the Tallgrass Equity credit facility. Borrowings under the credit facility bear interest, at Tallgrass Equity’s option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar rate, plus, in each case, an applicable margin. For loans bearing interest based on the base rate, the applicable margin is 1.50%, and for loans bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin is 2.50%.

We do not currently hedge the interest rate risk on our borrowings under the credit facilities. However, in the future we may consider hedging the interest rate risk or may consider choosing longer Eurodollar borrowing terms in order to fix all or a portion of our borrowings for a period of time. We estimate that a 1% increase in interest rates would decrease the fair value of the TEGP debt outstanding under the TEP and Tallgrass Equity credit facilities by $0.2 million based on our debt obligations as of September 30, 2015.

Credit Risk

We are exposed to credit risk. Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We manage our exposure to credit risk associated with customers to whom we extend credit through a credit approval process which includes credit analysis, the establishment of credit limits and ongoing monitoring procedures. We may request letters of credit, cash collateral, prepayments, guarantees or bonds as forms of credit support. We have historically experienced only minimal credit losses in connection with our receivables.

A substantial majority of our revenue is produced under long-term, firm, fee-based contracts with high-quality customers. The customer base we currently serve under these contracts generally has a strong credit profile, with the majority of our revenues derived from customers who have investment grade credit ratings or are part of corporate families with investment grade credit ratings as of September 30, 2015.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a- 15(e) or Rule 15d- 15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended September 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Assessment of Internal Control over Financial Reporting

The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules requiring every public company that files reports with the SEC to include a management report on such company’s internal control over financial reporting in its annual report. Pursuant to the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”), our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for up to five years or through such earlier date that we are no longer an “emerging growth company” as defined in the JOBS Act. Our first Annual Report on Form 10-K will not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by SEC rules applicable to newly public companies. Our management will be required to provide an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2016.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

See Note 14 – Legal and Environmental Matters to the condensed consolidated financial statements included in Part I—Item 1.— Financial Statements of this Quarterly Report, which is incorporated here by reference.

Item 1A. Risk Factors

Item 1A of our Form 10-Q for the quarter ended March 31, 2015 sets forth information relating to important risks and uncertainties that could materially adversely affect our business, financial condition or operating results. Those risk factors continue to be relevant to an understanding of our business, financial condition and operating results for the quarter ended September 30, 2015. There have been no material changes to the risk factors contained in our Form 10-Q for the quarter ended March 31, 2015.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits



Exhibit No.		Description

31.1*		Rule 13a-14(a)/15d-14(a) Certification of David G. Dehaemers, Jr.

31.2*		Rule 13a-14(a)/15d-14(a) Certification of Gary J. Brauchle.

32.1*		Section 1350 Certification of David G. Dehaemers, Jr.

32.2*		Section 1350 Certification of Gary J. Brauchle.

101.INS*		XBRL Instance Document.

101.SCH*		XBRL Taxonomy Extension Schema Document.

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.


* -	filed herewith

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		Tallgrass Energy GP, LP
		(registrant)
		By:	TEGP Management, LLC, its general partner

Date:	November 4, 2015	By:	/s/ Gary J. Brauchle
			Name:	Gary J. Brauchle
			Title:	Executive Vice President and Chief Financial Officer

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