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EX-32.1 - EXHIBIT 32.1 - Tallgrass Energy Partners, LPtep201693010qexhibit321.htm
EX-32.2 - EXHIBIT 32.2 - Tallgrass Energy Partners, LPtep201693010qexhibit322.htm
EX-31.2 - EXHIBIT 31.2 - Tallgrass Energy Partners, LPtep201693010qexhibit312.htm
EX-31.1 - EXHIBIT 31.1 - Tallgrass Energy Partners, LPtep201693010qexhibit311.htm
EX-12.1 - EXHIBIT 12.1 - Tallgrass Energy Partners, LPtep201693010qexhibit121.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
 
 
 FORM 10-Q
 
 
 
 (Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2016
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 001-35917
 
 
 
 
 Tallgrass Energy Partners, LP
(Exact name of registrant as specified in its charter)
 
 
 
Delaware
 
 
 
46-1972941
(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  x    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  x    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):
Large accelerated filer
 
x
  
Accelerated filer
 
¨
 
 
 
 
Non-accelerated filer
 
¨  (Do not check if a smaller reporting company)
  
Smaller reporting company
 
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x
On November 2, 2016, the Registrant had 72,115,405 Common Units and 834,391 General Partner Units outstanding.




TALLGRASS ENERGY PARTNERS, LP
TABLE OF CONTENTS
 




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.
Commodity sensitive contracts or arrangements: contracts or other arrangements, including tariff provisions, that directly expose our cash flows to increases and decreases in the price of commodities such as crude oil, natural gas and NGLs. Examples are Keep Whole Processing Contracts and Percent of Proceeds Processing Contracts, as well as pipeline loss allowances on our pipelines.
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 firm service assurance of capacity and deliverability to delivery points.
Delivery point: any point at which product in a pipeline is delivered to or for the account of a customer.
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.
FERC: Federal Energy Regulatory Commission.
Firm fee contracts: firm fee contracts generally obligate our customers to pay a fixed recurring charge to reserve an agreed upon amount of capacity and/or deliverability on our assets, regardless if the contracted capacity is actually used by the customer. Such contracts are also commonly known as "take-or-pay" contracts.
Firm services: services pursuant to which customers receive firm assurances regarding the availability of capacity and/or deliverability of natural gas, crude oil or other hydrocarbons or water on our assets up to a contracted amount.
Fractionation: the process by which NGLs are further separated into individual, typically 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.
Interruptible services: services pursuant to which customers receive limited, or no, assurances regarding the availability of capacity and deliverability in our assets.
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.
Long-term: with respect to any contract, a contract with an initial duration greater than one year.
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.
Produced water: all water removed from a well as a byproduct of the production of hydrocarbons and water removed from a well in connection with operations being conducted on the well, including naturally occurring water in the recovery formation, flow back water recovered during completion and fracturing operations and water entering the recovery formation through water flooding techniques.
Receipt point: the point where a product is received by or into a gathering system, processing facility, or transportation pipeline.
Reservoir: a porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (such as 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 transportation to end-user markets.
TBtu: one trillion British Thermal Units.
Tcf: one trillion cubic feet.




Throughput: the volume of products, such as crude oil, natural gas or water, 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.
Volumetric fee contracts: volumetric fee contracts generally obligate a customer to pay fees based upon the extent to which such customer utilizes our assets for midstream energy services. Unlike firm fee contracts, under volumetric fee contracts our customers are not generally required to pay a charge to reserve an agreed upon amount of capacity and/or deliverability.
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 PARTNERS, LP
CONDENSED CONSOLIDATED BALANCE SHEETS 
(UNAUDITED)
 
September 30, 2016
 
December 31, 2015
 
(in thousands)
ASSETS
 
Current Assets:
 
 
 
Cash and cash equivalents
$
417

 
$
1,611

Accounts receivable, net
53,085

 
57,757

Gas imbalances
890

 
1,227

Inventories
13,375

 
13,793

Derivative assets at fair value
25,690

 

Prepayments and other current assets
3,838

 
2,835

Total Current Assets
97,295

 
77,223

Property, plant and equipment, net
2,003,532

 
2,025,018

Goodwill
343,288

 
343,288

Intangible asset, net
94,280

 
96,546

Unconsolidated investment
455,401

 

Deferred financing costs, net
5,676

 
5,105

Deferred charges and other assets
10,816

 
14,894

Total Assets
$
3,010,288

 
$
2,562,074

LIABILITIES AND EQUITY
 
 
 
Current Liabilities:
 
 
 
Accounts payable (including $10,554 at December 31, 2015 related to variable interest entities)
$
17,046

 
$
22,218

Accounts payable to related parties
6,207

 
7,852

Gas imbalances
1,117

 
1,605

Derivative liabilities at fair value
197

 

Accrued taxes
20,676

 
13,844

Accrued liabilities
10,214

 
10,019

Deferred revenue
52,138

 
26,511

Other current liabilities
6,725

 
6,880

Total Current Liabilities
114,320

 
88,929

Long-term debt, net
1,398,003

 
753,000

Other long-term liabilities and deferred credits
7,341

 
5,143

Total Long-term Liabilities
1,405,344

 
758,143

Commitments and Contingencies

 

Equity:
 
 
 
Common unitholders (72,738,251 and 60,644,232 units issued and outstanding at September 30, 2016 and December 31, 2015, respectively)
2,094,821

 
1,618,766

General partner (834,391 units issued and outstanding at September 30, 2016 and December 31, 2015)
(637,945
)
 
(348,841
)
Total Partners' Equity
1,456,876

 
1,269,925

Noncontrolling interests
33,748

 
445,077

Total Equity
1,490,624

 
1,715,002

Total Liabilities and Equity
$
3,010,288

 
$
2,562,074


The accompanying notes are an integral part of these condensed consolidated financial statements.
1



TALLGRASS ENERGY PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
 
(in thousands, except per unit amounts)
Revenues:
 
 
 
 
 
 
 
Crude oil transportation services
$
91,387

 
$
81,928

 
$
279,281

 
$
206,331

Natural gas transportation services
31,444

 
29,431

 
89,406

 
90,620

Sales of natural gas, NGLs, and crude oil
20,758

 
20,252

 
51,514

 
62,132

Processing and other revenues
8,536

 
6,557

 
24,260

 
26,730

Total Revenues
152,125

 
138,168

 
444,461

 
385,813

Operating Costs and Expenses:
 
 
 
 
 
 
 
Cost of sales (exclusive of depreciation and amortization shown below)
18,590

 
18,186

 
48,116

 
54,959

Cost of transportation services (exclusive of depreciation and amortization shown below)
13,528

 
14,862

 
43,924

 
39,069

Operations and maintenance
14,714

 
14,071

 
41,055

 
36,054

Depreciation and amortization
20,831

 
20,802

 
64,099

 
61,762

General and administrative
13,147

 
11,807

 
40,072

 
37,947

Taxes, other than income taxes
6,717

 
5,521

 
19,862

 
16,547

Loss on disposal of assets

 

 
1,849

 
4,483

Total Operating Costs and Expenses
87,527

 
85,249

 
258,977

 
250,821

Operating Income
64,598

 
52,919

 
185,484

 
134,992

Other Income (Expense):
 
 
 
 
 
 
 
Interest expense, net
(10,907
)
 
(3,871
)
 
(27,639
)
 
(11,204
)
Unrealized (loss) gain on derivative instrument
(4,419
)
 

 
5,588

 

Equity in earnings of unconsolidated investment
12,066

 

 
35,387

 

Other income, net
480

 
502

 
1,267

 
1,983

Total Other (Expense) Income
(2,780
)
 
(3,369
)
 
14,603

 
(9,221
)
Net income
61,818

 
49,550

 
200,087

 
125,771

Net income attributable to noncontrolling interests
(1,084
)
 
(6,871
)
 
(3,235
)
 
(5,874
)
Net income attributable to partners
$
60,734

 
$
42,679

 
$
196,852

 
$
119,897

Allocation of income to the limited partners:
 
 
 
 
 
 
 
Net income attributable to partners
$
60,734

 
$
42,679

 
$
196,852

 
$
119,897

General partner interest in net income
(27,674
)
 
(12,146
)
 
(73,347
)
 
(30,614
)
Common and subordinated unitholders' interest in net income
33,060

 
30,533

 
123,505

 
89,283

Basic net income per common and subordinated unit
$
0.45

 
$
0.50

 
$
1.75

 
$
1.54

Diluted net income per common and subordinated unit
$
0.45

 
$
0.50

 
$
1.73

 
$
1.52

Basic average number of common and subordinated units outstanding
73,089

 
60,576

 
70,686

 
57,917

Diluted average number of common and subordinated units outstanding
74,063

 
61,536

 
71,590

 
58,884


The accompanying notes are an integral part of these condensed consolidated financial statements.
2




TALLGRASS ENERGY PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
 
Nine Months Ended September 30,
 
2016
 
2015
 
(in thousands)
Cash Flows from Operating Activities:
 
 
 
Net income
$
200,087

 
$
125,771

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization
68,693

 
64,624

Equity in earnings of unconsolidated investment
(35,387
)
 

Distributions from unconsolidated investment
35,387

 

Noncash compensation expense
4,270

 
3,988

Noncash change in fair value of derivative financial instruments
(5,391
)
 
(218
)
Loss on disposal of assets
1,849

 
4,483

Changes in components of working capital:
 
 
 
Accounts receivable and other
7,924

 
(11,538
)
Inventories
(867
)
 
(5,265
)
Accounts payable and accrued liabilities
4,827

 
6,786

Deferred revenue
25,303

 
13,995

Other operating, net
(779
)
 
(5,142
)
Net Cash Provided by Operating Activities
305,916

 
197,484

Cash Flows from Investing Activities:
 
 
 
Capital expenditures
(45,252
)
 
(65,146
)
Acquisition of unconsolidated affiliate
(436,022
)
 

Acquisition of Pony Express membership interest
(49,118
)
 
(700,000
)
Contributions to unconsolidated investment
(35,452
)
 

Distributions from unconsolidated investment in excess of cumulative earnings
16,073

 

Other investing, net
205

 
(4,625
)
Net Cash Used in Investing Activities
(549,566
)
 
(769,771
)
Cash Flows from Financing Activities:
 
 
 
Acquisition of Pony Express membership interest
(425,882
)
 

Proceeds from issuance of long-term debt
400,000

 

Proceeds from public offering, net of offering costs
290,474

 
551,243

Borrowings under revolving credit facility, net
252,000

 
137,000

Distributions to unitholders
(207,539
)
 
(113,260
)
Partial exercise of call option
(151,434
)
 

Proceeds from private placement, net of offering costs
90,009

 

Contributions from noncontrolling interests
8,700

 
19,303

Other financing, net
(13,872
)
 
(4,161
)
Net Cash Provided by Financing Activities
242,456

 
590,125

Net Change in Cash and Cash Equivalents
(1,194
)
 
17,838

Cash and Cash Equivalents, beginning of period
1,611

 
867

Cash and Cash Equivalents, end of period
$
417

 
$
18,705


The accompanying notes are an integral part of these condensed consolidated financial statements.
3




Schedule of Noncash Investing and Financing Activities:
 
 
 
Property, plant and equipment acquired via the cash management agreement with Tallgrass Development, LP
$

 
$
120,254

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


The accompanying notes are an integral part of these condensed consolidated financial statements.
4




TALLGRASS ENERGY PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(UNAUDITED)
 
Limited Partners
 
General Partner
 
Total Partners’ Equity
 
Noncontrolling Interests
 
Total Equity
 
Common
 
Subordinated
 
 
 
 
 
(in thousands)
Balance at January 1, 2016
$
1,618,766

 
$

 
$
(348,841
)
 
$
1,269,925

 
$
445,077

 
$
1,715,002

Net income
123,505

 

 
73,347

 
196,852

 
3,235

 
200,087

Issuance of units to public, net of offering costs
290,474

 

 

 
290,474

 

 
290,474

Issuance of units in a private placement, net of offering costs
90,009

 

 

 
90,009

 

 
90,009

Distributions to unitholders
(145,664
)
 

 
(61,875
)
 
(207,539
)
 

 
(207,539
)
Noncash compensation expense
5,931

 

 

 
5,931

 

 
5,931

Acquisition of additional 31.3% membership interest in Pony Express
268,607

 

 
(279,967
)
 
(11,360
)
 
(417,679
)
 
(429,039
)
Partial exercise of call option
(151,434
)
 

 
(25,858
)
 
(177,292
)
 

 
(177,292
)
Contributions from TD

 

 
5,308

 
5,308

 

 
5,308

Contributions from noncontrolling interest

 

 

 

 
8,700

 
8,700

Distributions to noncontrolling interest

 

 

 

 
(5,017
)
 
(5,017
)
Acquisition of noncontrolling interests
(5,373
)
 

 
(59
)
 
(5,432
)
 
(568
)
 
(6,000
)
Balance at September 30, 2016
$
2,094,821

 
$

 
$
(637,945
)
 
$
1,456,876

 
$
33,748

 
$
1,490,624

 
 
 
 
 
 
 
 
 
 
 
 
 
Limited Partners
 
General Partner
 
Total Partners’ Equity
 
Noncontrolling Interests
 
Total Equity
 
Common
 
Subordinated
 
 
 
 
 
(in thousands)
Balance at January 1, 2015
$
800,333

 
$
274,133

 
$
(35,743
)
 
$
1,038,723

 
$
756,428

 
$
1,795,151

Net income
84,103

 
5,180

 
30,614

 
119,897

 
5,874

 
125,771

Issuance of units to public, net of offering costs
551,243

 

 

 
551,243

 

 
551,243

Distributions to unitholders
(82,382
)
 
(7,857
)
 
(23,021
)
 
(113,260
)
 

 
(113,260
)
Noncash compensation expense
7,325

 

 

 
7,325

 

 
7,325

LTIP units tendered by employees to satisfy tax withholding obligations
(6,562
)
 

 

 
(6,562
)
 

 
(6,562
)
Contributions from noncontrolling interest

 

 

 

 
110,553

 
110,553

Distributions to noncontrolling interest

 

 

 

 
(44,543
)
 
(44,543
)
Acquisition of additional 33.3% membership interest in Pony Express

 

 
(324,328
)
 
(324,328
)
 
(375,672
)
 
(700,000
)
Acquisition of noncontrolling interests

 

 

 

 
(600
)
 
(600
)
Conversion of subordinated units
271,456

 
(271,456
)
 

 

 

 

Balance at September 30, 2015
$
1,625,516

 
$

 
$
(352,478
)
 
$
1,273,038

 
$
452,040

 
$
1,725,078



The accompanying notes are an integral part of these condensed consolidated financial statements.
5



TALLGRASS ENERGY PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. Description of Business
Tallgrass Energy Partners, LP ("TEP" or the "Partnership") is a publicly traded, growth-oriented limited partnership formed to own, operate, acquire and develop midstream energy assets in North America. "We," "us," "our" and similar terms refer to TEP together with its consolidated subsidiaries. We currently provide crude oil transportation to customers in Wyoming, Colorado, and the surrounding regions through Tallgrass Pony Express Pipeline, LLC ("Pony Express"), which owns a crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma that includes a lateral in Northeast Colorado that commences in Weld County, Colorado, and interconnects with the pipeline just east of Sterling, Colorado (the "Pony Express System"). We provide natural gas transportation and storage services for customers in the Rocky Mountain, Midwest and Appalachian regions of the United States through: (1) our 25% membership interest in Rockies Express Pipeline LLC ("Rockies Express"), a Delaware limited liability company which owns the Rockies Express Pipeline, a FERC-regulated natural gas pipeline system extending from Opal, Wyoming and Meeker, Colorado to Clarington, Ohio, (2) 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 (3) the Trailblazer Pipeline system, a FERC-regulated natural gas pipeline system extending from the Colorado and Wyoming border to Beatrice, Nebraska (the "Trailblazer Pipeline"). 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 (collectively, the "Midstream Facilities"), and NGL transportation services in Northeast Colorado. We perform water business services 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, Bakken, Marcellus and Utica shale formations.
Our reportable business segments are:
Crude Oil Transportation & Logistics—the ownership and operation of a FERC-regulated crude oil pipeline system;
Natural Gas Transportation & Logistics—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities; and
Processing & Logistics—the ownership and operation of natural gas processing, treating and fractionation facilities, the provision of water business services primarily to the oil and gas exploration and production industry and the transportation of NGLs.
The table below summarizes our equity ownership as of September 30, 2016:
Unit Holder
 
Limited Partner Common Units 
 
General Partner Units
 
Percentage of Outstanding Limited Partner Common Units
 
Percentage of Outstanding Common and General Partner Units
Public Unitholders (1)
 
43,427,917

 

 
59.70
%
 
59.04
%
Tallgrass Equity, LLC
 
20,000,000

 

 
27.50
%
 
27.18
%
Tallgrass Development, LP (2)
 
9,310,334

 

 
12.80
%
 
12.65
%
Tallgrass MLP GP, LLC (3)
 

 
834,391

 
%
 
1.13
%
Total (4)
 
72,738,251

 
834,391

 
100.00
%
 
100.00
%
(1) 
As discussed in Note 10Partnership Equity and Distributions, we issued and sold an additional 628,914 common units subsequent to September 30, 2016. As of November 2, 2016, there were 44,056,831 common units held by public unitholders outstanding.
(2) 
As discussed in Note 8 – Risk Management1,251,760 of the common units held by Tallgrass Development, LP ("TD") as of September 30, 2016 were subsequently deemed cancelled as of October 31, 2016. As of November 2, 2016, there were 8,058,574 common units held by TD outstanding.
(3) 
Tallgrass MLP GP, LLC (the "general partner") also holds all of TEP's incentive distribution rights.
(4) 
As of November 2, 2016, there were 72,949,796 total limited partner and general partner units outstanding.

6



2. Summary of Significant Accounting Policies
Basis of Presentation
These condensed consolidated financial statements and related notes for the three and nine months ended September 30, 2016 and 2015 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 year-end balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP for annual periods. The condensed consolidated financial statements for the three and nine months ended September 30, 2016 and 2015 include all normal, recurring adjustments and disclosures that we believe are necessary for a fair statement 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. Certain prior period amounts have been reclassified to conform to the current presentation.
Our financial results for the three and nine months ended September 30, 2016 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2016. The accompanying condensed consolidated interim financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2015 ("2015 Form 10-K") filed with the United States Securities and Exchange Commission (the "SEC") on February 17, 2016.
The condensed consolidated financial statements include the accounts of TEP and its subsidiaries and controlled affiliates. Significant intra-entity items have been eliminated in the presentation. Prior to January 1, 2016, Pony Express participated in a cash management agreement with TD, which currently holds a 2.0% common membership interest in Pony Express, under which cash balances were swept periodically and recorded as loans from Pony Express to TD. Effective January 1, 2016, Pony Express entered into a cash management agreement with TEP.
Net income or loss from consolidated subsidiaries that are not wholly-owned by TEP is attributed to TEP 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 TEP. Concurrent with TEP's acquisition of an initial 33.3% membership interest in 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 ended 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 are 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 liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit. Our consolidated VIEs do not have material assets that can only be used to settle specific obligations of the consolidated VIEs. Pony Express was considered to be a VIE under the applicable authoritative guidance prior to our acquisition of an additional 31.3% membership interest effective January 1, 2016. Effective January 1, 2016, Pony Express is no longer considered to be a VIE. We continue to consolidate our membership interest in Pony Express.

7



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.
Accounting Pronouncements Not Yet Adopted
Revenue Recognition
In May 2014, the FASB issued Accounting Standards Update ("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.
Throughout the first half of 2016, the FASB has issued a series of subsequent updates to the revenue recognition guidance in Topic 606, including ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, and ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients.
The amendments in ASU 2014-09, ASU 2016-08, ASU 2016-10, and ASU 2016-12 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. In light of this recently issued accounting guidance, we have started the process of reviewing our existing revenue contracts. Due to the early stage of this process, we are currently not in a position to estimate the impact the guidance will have on our consolidated financial statements. We expect to adopt the new standard on January 1, 2018 using the modified retrospective approach. This approach allows us to apply the new standard to (i) all new contracts entered into after January 1, 2018 and (ii) all existing contracts as of January 1, 2018 through a cumulative adjustment to equity. Consolidated revenues for periods prior to January 1, 2018 would not be revised.
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, but do not anticipate a material impact on our consolidated financial statements.
ASU No. 2016-02, "Leases (Topic 842)"
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). ASU 2016-02 provides a comprehensive update to the lease accounting topic in the Codification intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The amendments in ASU 2016-02 include a revised definition of a lease as well as certain scope exceptions. The changes primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP.

8



The amendments in ASU 2016-02 are effective for public entities for annual reporting periods beginning after December 15, 2018, and for interim periods within that reporting period. Early application is permitted. We are currently evaluating the impact of ASU 2016-02.
ASU No. 2016-09, "Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting"
In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Among other changes, ASU 2016-09 allows an entity to make an entity-wide accounting policy election to either estimate the number of awards expected to vest (consistent with current GAAP) or account for forfeitures when they occur.
The amendments in ASU 2016-09 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 2016-09, but do not anticipate a material impact on our consolidated financial statements.
Accounting Pronouncements Recently Adopted
ASU No. 2016-15, "Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments"
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. ASU 2016-15 provides explicit guidance on accounting for eight specific cash flow issues with the objective of reducing diversity in practice, including debt prepayment or debt extinguishment costs, settlement of certain debt instruments, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle.
The amendments in ASU 2016-015 are effective for public entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. We adopted the standard effective January 1, 2016. The adoption of ASU 2016-15 did not have a material impact on our financial position and results of operations.
ASU No. 2015-16, "Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments"
In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments. ASU 2015-16 simplifies the accounting for measurement-period adjustments for provisional amounts recognized in a business combination by eliminating the requirement for an acquirer to retrospectively account for measurement-period adjustments. Under the updated guidance, the acquirer must recognize adjustments in the reporting period in which the adjustment amounts are determined and the effect on earnings as a result of the change to the provisional amounts must be calculated as if the accounting had been completed at the acquisition date.
The amendments in ASU 2015-16 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2015. The adoption of ASU 2015-16 did not 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 changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. ASU 2015-02 modifies the evaluation of whether limited partnerships and other similar legal entities are considered VIEs or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, and changes 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. The adoption of ASU 2015-02 did not have a material impact on our financial position and results of operations.

9



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. The adoption of ASU 2014-12 did not have a material impact on our financial position and results of operations.
3. Acquisitions
Acquisition of a 25% Membership Interest in Rockies Express Pipeline LLC
On March 29, 2016, TD's indirect wholly owned subsidiary Rockies Express Holdings, LLC ("REX Holdings") signed a purchase agreement (the "REX Purchase Agreement") with a unit of Sempra U.S. Gas and Power ("Sempra") to acquire Sempra's 25% membership interest in Rockies Express for cash consideration of $440 million, subject to adjustment under the REX Purchase Agreement.
On April 28, 2016, we announced that TD offered TEP the right to assume the rights and obligations of REX Holdings under the REX Purchase Agreement. On May 6, 2016, TEP REX Holdings, LLC ("TEP REX"), an indirect wholly-owned subsidiary of TEP, and REX Holdings entered into an Assignment and Assumption Agreement pursuant to which REX Holdings assigned to TEP REX all of its rights under the REX Purchase Agreement and, in exchange, TEP REX assumed all of the rights and obligations of REX Holdings under the REX Purchase Agreement. Subsequently on May 6, 2016, TEP REX closed the purchase of a 25% membership interest in Rockies Express from Sempra pursuant to the REX Purchase Agreement for cash consideration of approximately $436.0 million, after making the adjustments to the purchase price required by the REX Purchase Agreement.
Our investment in Rockies Express is recorded under the equity method of accounting and reported as "Unconsolidated investment" on our condensed consolidated balance sheet. As of May 6, 2016, the difference between the fair value of our investment in Rockies Express of $436.0 million and the book value of the underlying net assets of approximately $840.7 million results in a negative basis difference of approximately $404.7 million. The basis difference has been allocated to property, plant and equipment and long-term debt based on their respective fair values at the date of acquisition. The amount of the basis difference allocated to property, plant and equipment is accreted over 35 years, which equates to the 2.86% composite depreciation rate utilized by Rockies Express to depreciate the underlying property, plant and equipment. The amount allocated to long-term debt is amortized over the remaining life of the various debt facilities. The basis difference at September 30, 2016 was allocated as follows:
 
Basis Difference
 
Amortization Period
 
(in thousands)
 
 
Long-term debt
$
7,878

 
2 - 25 years
Property, plant and equipment
(406,987
)
 
35 years
Total basis difference
$
(399,109
)
 

During the period from May 6, 2016 to September 30, 2016, we recognized equity in earnings from Rockies Express of $35.4 million, inclusive of the amortization of the negative basis difference discussed above, and received distributions from and made contributions to Rockies Express of $51.5 million and $35.5 million, respectively.

10



Summarized financial information for Rockies Express is as follows:
 
September 30, 2016
 
(in thousands)
Current assets
$
170,472

Noncurrent assets
$
6,058,941

Current liabilities
$
173,447

Noncurrent liabilities
$
2,638,071

Members' equity
$
3,417,895

 
Three Months Ended September 30, 2016
 
Period from May 6, 2016 to September 30, 2016
 
(in thousands)
Revenue
$
159,421

 
$
257,582

Operating income
$
66,436

 
$
110,268

Net income to Members
$
34,184

 
$
118,925

Acquisition of Additional 31.3% Membership Interest in Pony Express
Effective January 1, 2016, TEP acquired an additional 31.3% membership interest in Pony Express in exchange for cash consideration of $475 million and 6,518,000 TEP common units (valued at approximately $268.6 million based on the December 31, 2015 closing price of our common units) issued to TD, for total consideration of approximately $743.6 million. The transaction increased our aggregate membership interest in Pony Express to 98.0%. As part of the transaction, TD granted us an 18 month call option covering the newly issued 6,518,000 common units at a price of $42.50. On the effective date of the acquisition, the call option was valued at $46.0 million. As discussed in Note 8Risk Management, on July 21, 2016, we partially exercised the option covering 3,563,146 of the common units. On October 31, 2016, we partially exercised the option covering 1,251,760 of the common units, leaving 1,703,094 remaining common units subject to the call option as of November 2, 2016. As a result of the partial exercise on July 21, 2016, TEP derecognized a portion of the derivative asset balance, recognizing approximately $25.9 million through equity during the nine months ended September 30, 2016, as discussed further in Note 10Partnership Equity and Distributions.
The acquisition of the additional 31.3% 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 has not been recast to reflect the additional 31.3% membership interest. The transaction resulted in a deemed distribution to our general partner as discussed further in Note 10Partnership Equity and Distributions.
Cash outflows to acquire an additional noncontrolling interest in Pony Express are classified as an investing activity in the accompanying condensed consolidated statements of cash flows to the extent the consideration paid was used to directly fund the construction of the underlying assets by the noncontrolling member. Cash outflows to acquire an additional noncontrolling interest in excess of the cost to construct the underlying assets are classified as financing activities. For the nine months ended September 30, 2016, $49.1 million of the $475 million paid to acquire the additional 31.3% membership interest in Pony Express was classified as an investing activity and $425.9 million was classified as a financing activity.
TEP Acquisition of BNN Western, LLC
On December 16, 2015, Whiting Oil and Gas Corporation ("Whiting"), BNN Redtail, LLC ("Redtail"), and BNN Western, LLC ("Western"), a newly formed Delaware limited liability company, entered into a definitive Transfer, Purchase and Sale Agreement, pursuant to which Redtail acquired 100% of the outstanding membership interests of Western from Whiting in exchange for total cash consideration of $75 million. Western's assets consist of a fresh water delivery and storage system and produced water gathering and produced water disposal system, which together comprise 62 miles of pipeline along with associated fresh water ponds and disposal wells. As part of the transaction with Whiting, Whiting also executed a five-year fresh water service contract and a nine-year gathering and disposal contract.
At December 31, 2015, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. The $75 million purchase price of the assets was allocated entirely to property, plant and equipment. No adjustments were made to these provisional amounts and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of September 30, 2016.

11



TEP's unaudited pro forma revenue and net income attributable to partners for the three and nine months ended September 30, 2015 is presented below as if the acquisition of Western had been completed on January 1, 2015:
 
Three Months Ended September 30, 2015
 
Nine Months Ended September 30, 2015
 
(in thousands)
Revenue
$
138,651

 
$
387,245

Net income attributable to partners
$
42,847

 
$
120,395

The pro forma financial information is not necessarily indicative of what the actual results of operations or financial position of TEP would have been if the transactions had in fact occurred on the date or for the period indicated, nor do they purport to project the results of operations or financial position of TEP for any future periods or as of any date. The pro forma financial information does not give effect to any cost savings, operating synergies, or revenue enhancements expected to result from the transactions or the costs to achieve these cost savings, operating synergies, and revenue enhancements. The pro forma revenue and net income includes adjustments to give effect to TEP's consolidated interest in the estimated results of operations of Western for the periods presented.
Acquisition of Additional Membership Interest in Water Solutions
On July 1, 2016, we acquired the remaining 8% noncontrolling equity interest in Water Solutions and additional interests in certain of Water Solutions' subsidiaries from Regency Investments I, LLC and BSEG Water Group LLC for total cash consideration of $6.0 million, which will be accounted for as an acquisition of noncontrolling interest. Subsequent to the closing of the transaction, our aggregate membership interest in Water Solutions is 100%.
4. 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.
There was no interest income from TD recognized for the three and nine months ended September 30, 2016. During the nine months ended September 30, 2015 we recognized interest income from TD of $0.4 million on the receivable balance under the Pony Express cash management agreement in effect through December 31, 2015.
Transactions with affiliated companies, excluding transactions otherwise disclosed, are as follows:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
 
(in thousands)
Cost of transportation services
$
7,313

 
$
7,180

 
$
21,864

 
$
17,771

Charges to TEP: (1)
 
 
 
 
 
 
 
Property, plant and equipment, net
$
432

 
$
958

 
$
1,953

 
$
3,859

Operation and maintenance
$
6,317

 
$
6,077

 
$
18,778

 
$
17,325

General and administrative
$
9,567

 
$
9,541

 
$
28,784

 
$
28,112

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

12



Details of balances with affiliates included in "Accounts receivable, net" and "Accounts payable to related parties" in the condensed consolidated balance sheets are as follows:
 
September 30, 2016
 
December 31, 2015
 
(in thousands)
Receivable from related parties:
 
 
 
Rockies Express Pipeline LLC
$
126

 
$
15

Total receivable from related parties
$
126

 
$
15

Accounts payable to related parties:
 
 
 
Tallgrass Operations, LLC
$
6,139

 
$
7,792

Tallgrass Equity, LLC
68

 
36

Deeprock Development, LLC

 
17

Rockies Express Pipeline LLC

 
7

Total accounts payable to related parties
$
6,207

 
$
7,852

Balances of gas imbalances with affiliated shippers are as follows:
 
September 30, 2016
 
December 31, 2015
 
(in thousands)
Affiliate gas imbalance receivables
$
82

 
$
92

Affiliate gas imbalance payables
$
161

 
$
227

5. Inventory
The components of inventory at September 30, 2016 and December 31, 2015 consisted of the following:
 
September 30, 2016
 
December 31, 2015
 
(in thousands)
Crude oil
$
4,223

 
$
2,661

Materials and supplies
6,505

 
8,581

Natural gas liquids
255

 
395

Gas in underground storage
2,392

 
2,156

Total inventory
$
13,375

 
$
13,793

6. Property, Plant and Equipment
A summary of net property, plant and equipment by classification is as follows:
 
September 30, 2016
 
December 31, 2015
 
(in thousands)
Crude oil pipelines
$
1,182,806

 
$
1,172,684

Natural gas pipelines
553,437

 
550,710

Processing and treating assets
256,331

 
254,073

Water business assets
81,507

 
81,098

General and other
71,190

 
69,181

Construction work in progress
38,454

 
30,699

Accumulated depreciation and amortization
(180,193
)
 
(133,427
)
Total property, plant and equipment, net
$
2,003,532

 
$
2,025,018


13



7. Goodwill
Annual Goodwill Impairment Analysis
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 fair value over carrying amount in the last valuation or changes in the business environment. Our annual impairment testing date is August 31. 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 2016 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 2016. 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.
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 crude oil and natural gas include, among others (i) pre-existing or anticipated physical crude oil and 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.

14



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, 2016
 
December 31, 2015
 
 
 
(in thousands)
Call option derivative (1)
Current assets
 
$
25,690

 
$

Natural gas derivative contracts (2)
Current liabilities
 
$
190

 
$

Crude oil derivative contract (3)
Current liabilities
 
$
7

 
$

(1) 
As discussed in Note 3Acquisitions, in conjunction with our acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016, TD granted us an 18 month call option covering the 6,518,000 common units issued to TD.
(2) 
As of September 30, 2016, the fair value shown for natural gas derivative contracts was comprised of derivative volumes for short natural gas fixed-price swaps totaling 0.8 Bcf. As of December 31, 2015 there were no natural gas derivative contracts outstanding.
(3) 
As of September 30, 2016, the fair value shown for crude oil derivative contracts was comprised of the sale of 30,000 barrels in October 2016. As of December 31, 2015 there were no crude oil 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, 2016 and 2015:
 
Location of gain (loss) recognized
in income on derivatives
 
Amount of gain (loss) recognized in income on derivatives
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2016
 
2015
 
2016
 
2015
 
 
 
(in thousands)
Derivatives not designated as hedging contracts:
 
 
 
 
 
 
 
 
 
Call option derivative
Unrealized (loss) gain on derivative instrument
 
$
(4,419
)
 
$

 
$
5,588

 
$

Natural gas derivative contracts
Sales of natural gas, NGLs, and crude oil
 
$
161

 
$
252

 
$
(190
)
 
$
211

Crude oil derivative contract
Sales of natural gas, NGLs, and crude oil
 
$
318

 
$

 
$
466

 
$

Exercise of Call Option
On July 21, 2016, we partially exercised the call option granted by TD in January 2016 as discussed in Note 3Acquisitions covering 3,563,146 common units for a cash payment of $151.4 million. On October 31, 2016, we partially exercised the call option again covering an additional 1,251,760 common units for a cash payment of $53.2 million. These common units were deemed canceled upon the exercise of the call option and as of such exercise date were no longer issued and outstanding. As of November 2, 2016, 1,703,094 common units remained subject to the call option.
Credit Risk
We have counterparty credit risk as a result of our use of derivative contracts. Counterparties to our crude oil and natural gas derivatives 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. The counterparty to our call option derivative is TD.

15



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. As of September 30, 2016, the fair value of our crude oil and natural gas derivative contracts were a liability, resulting in no credit exposure from TEP's counterparties as of that date.
As of September 30, 2016 and December 31, 2015, 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 any margin deposits with counterparties associated with natural gas 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 commodity 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. The call option granted by TD is valued using a Black-Scholes option pricing model. Key inputs to the valuation model include the term of the option, risk free rate, the exercise price and current market price, expected volatility and expected distribution yield of the underlying units. The call option valuation is classified within Level 2 of the fair value hierarchy as the value is based on significant observable inputs.
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.

16



The following table summarizes the fair value measurements of our derivative contracts as of September 30, 2016 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, 2016:
 
 
 
 
 
 
 
Call option derivative
$
25,690

 
$

 
$
25,690

 
$

 
 
 
 
 
 
 
 
 
 
 
Liability 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, 2016:
 
 
 
 
 
 
 
Natural gas derivative contracts
$
190

 
$

 
$
190

 
$

Crude oil derivative contract
$
7

 
$

 
$
7

 
$

9. Long-term Debt
Long-term debt consisted of the following at September 30, 2016 and December 31, 2015:
 
September 30, 2016
 
December 31, 2015
 
(in thousands)
Revolving credit facility
$
1,005,000

 
$
753,000

5.50% senior notes due September 15, 2024
400,000

 

Less: Deferred financing costs, net (1)
(6,997
)
 

Total long-term debt, net
$
1,398,003

 
$
753,000

(1) 
Deferred financing costs, net as presented above relate solely to the 2024 Notes. Deferred financing costs associated with our revolving credit facility are presented in noncurrent assets on our condensed consolidated balance sheets.
Senior Unsecured Notes
On September 1, 2016, TEP and Tallgrass Energy Finance Corp. (the "Co-Issuer" and together with TEP, the "Issuers"), the Guarantors named therein and U.S. Bank, National Association, as trustee, entered into an Indenture dated September 1, 2016 (the "Indenture"), pursuant to which the Issuers issued $400 million in aggregate principal amount of 5.50% senior notes due 2024 (the "2024 Notes"). TEP used the net proceeds of the offering to repay outstanding borrowings under its existing senior secured revolving credit facility.
The 2024 Notes are general unsecured senior obligations of the Issuers. The 2024 Notes are unconditionally guaranteed jointly and severally on a senior unsecured basis by TEP's existing direct and indirect wholly owned subsidiaries (other than the Co-Issuer) and certain of TEP's future subsidiaries (the "Guarantors"). The 2024 Notes rank equal in right of payment with all existing and future senior indebtedness of the Issuers, and senior in right of payment to any future subordinated indebtedness of the Issuers. The 2024 Notes will mature on September 15, 2024 and interest on the 2024 Notes is payable in cash semi-annually in arrears on each March 15 and September 15, commencing March 15, 2017. TEP may redeem the 2024 Notes prior to their scheduled maturity at the applicable redemption price set forth in the Indenture, plus accrued and unpaid interest.

17



The Indenture contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests, repurchase equity securities or redeem subordinated securities; (iv) make investments; (v) restrict distributions, loans or other asset transfers from TEP's restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of TEP's properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates. As of September 30, 2016, we are in compliance with the covenants required under the 2024 Notes.
Revolving Credit Facility
Effective January 4, 2016, in connection with the acquisition of an additional 31.3% membership interest in Pony Express, TEP exercised the committed accordion feature to increase the total capacity of the revolving credit facility from $1.1 billion to $1.5 billion. In connection with the acquisition of a 25% membership interest in Rockies Express, TEP amended the revolving credit facility to increase the total capacity to $1.75 billion, which increase became effective May 6, 2016.
The following table sets forth the available borrowing capacity under the revolving credit facility as of September 30, 2016 and December 31, 2015:
 
September 30, 2016
 
December 31, 2015
 
(in thousands)
Total capacity under the revolving credit facility
$
1,750,000

 
$
1,100,000

Less: Outstanding borrowings under the revolving credit facility (1)
(1,005,000
)
 
(753,000
)
Available capacity under the revolving credit facility
$
745,000

 
$
347,000

(1) 
As of October 31, 2016, our outstanding borrowings under the revolving credit facility were approximately $1.003 billion.
The revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict our ability (as well as the ability of our 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 our 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, we are 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, 2016, we are 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, which ranges from 0.300% to 0.500%, based on our total leverage ratio. As of September 30, 2016, the weighted average interest rate on outstanding borrowings was 2.28%. During the nine months ended September 30, 2016, our weighted average effective interest rate, including the interest on outstanding borrowings, commitment fees, and amortization of deferred financing costs, was 2.72%.
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, 2016 and December 31, 2015, 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)
As of September 30, 2016:
 
 
 
 
 
 
 
 
 
Revolving credit facility
$

 
$
1,005,000

 
$

 
$
1,005,000

 
$
1,005,000

2024 Notes
$

 
$
403,752

 
$

 
$
403,752

 
$
393,003

As of December 31, 2015:
 
 
 
 
 
 
 
 
 
Revolving credit facility
$

 
$
753,000

 
$

 
$
753,000

 
$
753,000


18



The long-term debt borrowed under the revolving credit facility is carried at amortized cost. As of September 30, 2016 and December 31, 2015, the fair value of borrowings under the revolving credit facility approximates the carrying amount of the borrowings using a discounted cash flow analysis. The 2024 Notes are carried at amortized cost, net of deferred financing costs. The estimated fair value of the 2024 Notes is based upon quoted market prices adjusted for illiquid markets.
We are not aware of any factors that would significantly affect the estimated fair value subsequent to September 30, 2016.
10. Partnership Equity and Distributions
Equity Distribution Agreements
On October 31, 2014, we entered into an equity distribution agreement pursuant to which we may sell from time to time through a group of managers, as our sales agents, common units representing limited partner interests having an aggregate offering price of up to $200 million. On May 13, 2015 the amount was subsequently amended to $100.2 million in order to account for follow-on equity offerings under our S-3 shelf registration statement. On May 17, 2016, we entered into a new equity distribution agreement allowing for the sale of common units with an aggregate offering price of up to $657.5 million. Sales of common units, if any, will be made by means of ordinary brokers' transactions, to or through a market maker or directly on or through an electronic communication network, a "dark pool" or any similar market venue, or as otherwise agreed by the Partnership and one or more of the managers. We intend to use the net cash proceeds from any sale of the units for general partnership purposes, which may include, among other things, the Partnership's exercise of the call option with respect to the 6,518,000 common units issued to TD in connection with the Partnership's acquisition of an additional 31.3% of Pony Express in January 2016, repayment or refinancing of debt, funding for acquisitions, capital expenditures and additions to working capital.
During the three months ended September 30, 2016, we issued and sold 622,846 common units with a weighted average sales price of $47.39 per unit under our equity distribution agreements for net cash proceeds of approximately $28.7 million (net of approximately $0.8 million in commissions and professional service expenses). During the nine months ended September 30, 2016, we issued and sold 6,703,984 common units with a weighted average sales price of $43.98 per unit under our equity distribution agreements for net cash proceeds of approximately $290.5 million (net of approximately $4.4 million in commissions and professional service expenses). During the period from October 1, 2016 to November 2, 2016, we issued and sold an additional 628,914 common units with a weighted average sales price of $48.05 per unit under our equity distribution agreement for net cash proceeds of approximately $29.9 million (net of approximately $0.3 million in commissions and professional service expenses). We used the net cash proceeds for general partnership purposes as described above.
Private Placement
On April 28, 2016, we issued an aggregate of 2,416,987 common units for net cash proceeds of $90.0 million in a private placement transaction to certain funds managed by Tortoise Capital Advisors, L.L.C. The units were subsequently registered pursuant to our Form S-3/A (File No. 333-210976) filed with the SEC on May 6, 2016, which became effective May 17, 2016.
Tallgrass Development Purchase Program
On February 17, 2016, TEP and Tallgrass Energy GP, LP ("TEGP") announced that the Board of Directors of Tallgrass Energy Holdings, LLC, the sole member of TEGP's general partner and the general partner of TD, has authorized an equity purchase program under which TD may initially purchase up to an aggregate of $100 million of the outstanding Class A shares of TEGP or the outstanding common units of TEP. TD may purchase Class A shares or Common Units from time to time on the open market or in negotiated purchases. The timing and amounts of any such purchases will be subject to market conditions and other factors, and will be in accordance with applicable securities laws and other legal requirements. The purchase plan does not obligate TD to acquire any specific number of Class A shares or Common Units and may be discontinued at any time. No purchases were made under this program during the nine months ended September 30, 2016.

19



Distributions to Holders of Common Units, General Partner Units and Incentive Distribution Rights
Our partnership agreement requires us to distribute our available cash, as defined in the partnership agreement, to unitholders of record on the applicable record date within 45 days after the end of each quarter. The following table shows the distributions for the periods indicated:
 
 
 
 
Distributions
 
 
  
 
 
 
Limited Partner
Common Units
 
General Partner
 
 
 
Distributions
per Limited
Partner Unit
Three Months Ended
 
Date Paid
 
Incentive Distribution Rights
 
General Partner Units
 
Total
 
 
 
 
 
(in thousands, except per unit amounts)
 
 
September 30, 2016
 
November 14, 2016 (1)
 
$
57,332

 
$
26,987

 
$
976

 
$
85,295

 
$
0.7950

June 30, 2016
 
August 12, 2016
 
54,442

 
24,262

 
911

 
79,615

 
0.7550

March 31, 2016
 
May 13, 2016
 
48,238

 
19,816

 
830

 
68,884

 
0.7050

December 31, 2015
 
February 12, 2016
 
42,984

 
15,332

 
724

 
59,040

 
0.6400

September 30, 2015
 
November 13, 2015
 
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

(1) 
The distribution announced on October 5, 2016 for the third quarter of 2016 will be paid on November 14, 2016 to unitholders of record at the close of business on October 31, 2016.
Other Contributions and Distributions
During the nine months ended September 30, 2016, TEP was deemed to have made noncash capital distributions of $280.0 million and $25.9 million to the general partner, which represent the excess purchase price over the carrying value of the additional 31.3% membership interest in Pony Express acquired effective January 1, 2016 and the derecognition of a portion of the derivative asset associated with the partial exercise of the call option, respectively. See Note 3Acquisitions for additional information regarding these transactions. During the nine months ended September 30, 2016, TEP also received contributions of $5.3 million from TD to indemnify TEP for costs associated with Trailblazer's Pipeline Integrity Management Program, as discussed in Note 13Legal and Environmental Matters, and received contributions and distributions from noncontrolling interests of $8.7 million and $5.0 million, which primarily consisted of activity associated with TD's 2% noncontrolling interest in Pony Express.
During the nine months ended September 30, 2015, TEP was deemed to have made a noncash capital distribution of $324.3 million to the general partner, which represents the excess purchase price over the carrying value of the additional 33.3% membership interest in Pony Express acquired effective March 1, 2015. TEP also recognized contributions from noncontrolling interests of $110.6 million, which consisted primarily of contributions from TD to Pony Express to fund construction of the lateral in Northeast Colorado, and distributions to noncontrolling interests of $44.5 million.
11. Net Income per Limited Partner Unit
The Partnership's net income is allocated to the general partner and the limited partners, including the holders of the subordinated units, in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner. Basic and diluted net income per limited partner unit is calculated by dividing limited partners' interest in net income, less general partner incentive distributions, by the weighted average number of outstanding limited partner units during the period.
We compute earnings per unit using the two-class method for Master Limited Partnerships as prescribed in the FASB guidance. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.
We calculate net income available to limited partners based on the distributions pertaining to the current period's net income. After adjusting for the appropriate period's distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner and limited partners in accordance with the contractual terms of the partnership agreement and as further prescribed in the FASB guidance under the two-class method.
The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights (which are currently held by our general partner), even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit.
Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit reflects the potential dilution of common equivalent units that could occur if equity participation units are converted into common units.
The following table illustrates the Partnership's calculation of net income per common and subordinated unit for the three and nine months ended September 30, 2016 and 2015:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
 
(in thousands, except per unit amounts)
Net income
$
61,818

 
$
49,550

 
$
200,087

 
$
125,771

Net income attributable to noncontrolling interests
(1,084
)
 
(6,871
)
 
(3,235
)
 
(5,874
)
Net income attributable to partners
60,734

 
42,679

 
196,852

 
119,897

General partner interest in net income
(27,674
)
 
(12,146
)
 
(73,347
)
 
(30,614
)
Net income available to common and subordinated unitholders
$
33,060

 
$
30,533

 
$
123,505

 
$
89,283

Basic net income per common and subordinated unit
$
0.45

 
$
0.50

 
$
1.75

 
$
1.54

Diluted net income per common and subordinated unit
$
0.45

 
$
0.50

 
$
1.73

 
$
1.52

Basic average number of common and subordinated units outstanding
73,089

 
60,576

 
70,686

 
57,917

Equity Participation Unit equivalent units
974

 
960

 
904

 
967

Diluted average number of common and subordinated units outstanding
74,063

 
61,536

 
71,590

 
58,884

12. Regulatory Matters
There are currently no proceedings challenging the currently effective transportation rates of Pony Express, Rockies Express or Trailblazer Pipeline Company LLC ("Trailblazer"). On October 30, 2015, Tallgrass Interstate Gas Transmission, LLC ("TIGT") filed a general rate case with the FERC pursuant to Section 4 of the Natural Gas Act ("NGA"), discussed in more detail below. Regulators, as well as shippers, do have rights, under circumstances prescribed by applicable law, to challenge the rates that we charge at our regulated entities. Further, applicable law 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 like the Pony Express System 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.

20



TIGT
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 NGA. The rate case proposed 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 incremental charges, including (i) a charge for deliveries made to points without certain electronic flow measurement equipment, and (ii) a Cost Recovery Mechanism ("CRM") charge to completely or partially reimburse TIGT for certain costs it incurred to maintain system safety, environmental compliance and reliability. 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/over collection and the forecasted FL&U expense for the upcoming period. TIGT also proposed to implement a power cost tracker to recover the actual power costs incurred by TIGT to power its compressors. 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, had a right to challenge any aspect of TIGT's rate case filing. Accordingly, numerous TIGT customers protested aspects of TIGT's NGA Section 4 rate filing.
On November 30, 2015, the FERC issued an order accepting and suspending the proposed rates and certain proposed tariff records to be effective upon motion May 1, 2016, subject to refund, certain modifications to TIGT's proposed CRM charge, and the outcome of an evidentiary hearing before a FERC Administrative Law Judge (the "Suspension Order"). In the Suspension Order, the FERC also accepted two tariff records related to force majeure events and reservation charge crediting to be effective December 1, 2015, subject to certain modifications. On December 21, 2015, TIGT made a compliance filing with the FERC to modify TIGT's proposed CRM charge and update the tariff records related to force majeure events and reservation charge crediting as directed by the FERC in the Suspension Order. No comments or protests were filed in response to the compliance filing and the FERC accepted the compliance filing on February 1, 2016. On March 22, 2016, a Settlement Judge was appointed in the case to assist the participants in exploring the possibility of settlement. On March 31, 2016, the FERC issued an order denying certain rehearing requests concerning the CRM, granting in part a motion to remove certain pro forma tariff records from the hearing, and also requested comments in order to assess the need for a technical conference. The FERC also retained for resolution through hearing the pro forma tariff records related to TIGT's proposed charge at delivery points lacking electronic flow measurement and removed from hearing the other issues related to the pro forma tariff records. Whether any issues will be resolved through technical conference is pending. The FERC also directed TIGT to provide additional information related to certain pro forma tariff records, which TIGT filed on April 14, 2016. On June 23, 2016, the FERC approved the implementation of TIGT's filed postage stamp rates, subject to refund, effective on May 1, 2016.
TIGT has reached an agreement in principle with customers representing a majority of firm fee revenue on the TIGT System for the year ended December 31, 2015 to settle all rate related issues set for hearing in its existing FERC rate case, including the issues of a cost recovery mechanism and a non-Electronic Flow Measurement charge. On May 5, 2016, the Acting Chief Administrative Law Judge issued an Order suspending the procedural schedule in the case as a result of the agreement in principle. On June 8, 2016, TIGT filed with the FERC its offer of settlement which resolves all issues in the case, with the exception of certain non-rate related tariff issues which remain subject to the FERC's review and approval. On June 9, 2016, the Presiding Administrative Law Judge issued an Order shortening the period for any comments on the settlement, such that comments were due by June 13, 2016. No adverse comments were filed. The offer of settlement was certified to the FERC by the Administrative Law Judge on July 14, 2016. The Judge found that the settlement is uncontested, presents no issues of first impression, has no FERC policy implications, and appears to be just, reasonable, and in the public interest. The FERC issued an order on November 2, 2016 approving the settlement, finding that it appears to be fair and reasonable and in the public interest.
Trailblazer
2016 Annual Fuel Tracker Filing – FERC Docket Nos. RP16-814-000 and RP16-814-001
On April 1, 2016, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2016 in Docket No. RP16-814-000. The FERC accepted this filing on April 18, 2016. On May 19, 2016, Trailblazer filed its refund report associated with the April 1, 2016 annual fuel tracker filing, which the FERC accepted on July 11, 2016.
On September 7, 2016, Trailblazer filed an adjustment to its April 1, 2016 fuel tracker filing. As a result of this adjustment, Trailblazer proposed to issue additional cash-out refunds to applicable shippers and also reflect this adjustment in its applicable fuel accounts. The FERC accepted this filing on October 3, 2016. On October 14, 2016, Trailblazer filed its refund report associated with its September 7, 2016 adjustment filing.

21



Rockies Express
Annual FERC Fuel Tracking Filings – FERC Docket Nos. RP16-702-000 and RP16-1301-000
On March 1, 2016, Rockies Express made its annual fuel tracker filing with a proposed effective date of April 1, 2016 in Docket No. RP16-702. The FERC issued an order accepting the filing on March 25, 2016.
On September 30, 2016, Rockies Express elected to make an interim fuel tracker filing with a proposed effective date of November 1, 2016 in Docket No. RP16-1301-000. This interim filing proposes increases to most applicable fuel and power rates as a result of increased system utilization. On October 12, 2016, certain shippers filed a protest with the FERC regarding the proposed increases. Rockies Express filed a response to the protest on October 20, 2016, to which the shippers replied on October 25, 2016. On October 20, 2016, Rockies Express also filed an errata to rates applicable to a pooling and wheeling service. The FERC set a November 1, 2016 comment deadline on the errata filing. The interim filing remains pending before the FERC.
Seneca Lateral Facilities Conversion – FERC Docket No. CP15-102-000
On March 2, 2015 in Docket No. CP15-102-000, Rockies Express filed with the FERC an application for (1) authorization to convert certain existing and operating pipeline and compression facilities located in Noble and Monroe Counties, Ohio (Seneca Lateral Facilities described in Docket Nos. CP13-539-000 and CP14-194-000) from Natural Gas Policy Act of 1978 Section 311 authority to Natural Gas Act Section 7 jurisdiction, and (2) issuance of a certificate of public convenience and necessity authorizing Rockies Express to operate and maintain the Seneca Lateral Facilities. On April 7, 2016, the FERC issued a Certificate to Rockies Express granting its requested authorizations. As directed by the FERC, Rockies Express filed revised rates for Natural Gas Act service on the Seneca Lateral, and the Seneca Lateral commenced Natural Gas Act service on June 1, 2016.
Rockies Express Zone 3 Capacity Enhancement Project – FERC Docket No. CP15-137-000
On March 31, 2015 in Docket No. CP15-137-000, Rockies Express filed with the FERC an application for authorization to construct and operate (1) three new mainline compressor stations located in Pickaway and Fayette Counties, Ohio and Decatur County, Indiana; (2) additional compressors at an existing compressor station in Muskingum County, Ohio; and (3) certain ancillary facilities. The proposed facilities will increase the Rockies Express Zone 3 east-to-west mainline capacity by 800,000 Dth/d from receipts at Clarington, Ohio to corresponding deliveries of 520,000 Dth/d and 280,000 Dth/d to Lebanon, Ohio and Moultrie County, Illinois, respectively. Pursuant to the FERC's obligations under the National Environmental Policy Act, FERC staff issued an Environmental Assessment for the project on August 31, 2015. On February 25, 2016, the FERC issued a Certificate of Public Convenience and Necessity authorizing Rockies Express to proceed with the project. On March 14, 2016, Rockies Express commenced construction of the project facilities.
13. 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 no reserve for legal claims as of September 30, 2016 or December 31, 2015.
Rockies Express
Mineral Management Service Lawsuit
On June 30, 2009, Rockies Express filed claims against Mineral Management Service, a former unit of the U.S. Department of Interior (collectively "Interior") for breach of its contractual obligation to sign transportation service agreements for pipeline capacity that it had agreed to take on Rockies Express. The Civilian Board of Contract Appeals ("CBCA") conducted a trial and ruled that Interior was liable for breach of contract, but limited the damages Interior was required to pay. On September 13, 2013, the United States Court of Appeals for the Federal Circuit issued a decision affirming that Interior was liable for its breach of contract, but reversing the CBCA's decision to limit damages. The case was remanded to the CBCA for the purpose of calculating damages at a hearing. On May 20, 2016, Rockies Express and Interior agreed to resolve the claims in this matter in exchange for a $65 million cash payment to Rockies Express. Interior paid the amount due Rockies Express on June 23, 2016.

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Ultra Resources
In early 2016, Ultra Resources, Inc. ("Ultra") defaulted on its firm transportation service agreement for approximately 0.2 Bcf/d through November 11, 2019. In late March 2016, Rockies Express terminated Ultra's service agreement. On April 14, 2016, Rockies Express filed a lawsuit against Ultra for breach of contract and damages in Harris County, Texas, in which Rockies Express seeks approximately $303 million in damages and other relief. Specifically, Rockies Express has asserted that Ultra owes approximately $303 million for past transportation service charges and for reservation charge fees that Rockies Express would have received over the term of the service agreement had Ultra not defaulted, in addition to other amounts owed under law or equity.
On April 29, 2016, Ultra and certain of its debtor affiliates filed for protection under Chapter 11 of the United States Bankruptcy Code in United States Bankruptcy Court for the Southern District of Texas. On May 10, 2016, Ultra filed a notice of bankruptcy in the Harris County state court proceeding, which asserted that pursuant to section 362(a) of the Bankruptcy Code, the filing of Ultra's Chapter 11 petition operated as a stay of the Harris County state court proceeding. Accordingly, Rockies Express intends to pursue its approximately $303 million claim in Ultra's Chapter 11 proceeding.
Michels Corporation
On June 17, 2014, Michels Corporation ("Michels") filed a complaint and request for relief against Rockies Express in the Court of Common Pleas, Monroe County, Ohio, as a result of work performed by Michels to construct the Seneca Lateral Pipeline in Ohio. Michels seeks unspecified damages from Rockies Express and asserts claims of breach of contract, negligent misrepresentation, unjust enrichment and quantum meruit. Michels has also filed notices of Mechanic's Liens in Monroe and Noble Counties, asserting $24.2 million as the amount due. The case is currently scheduled to go to trial in April 2017. Rockies Express also previously filed Petition for Declaratory Judgment, Injunctive Relief and Damages against Michels in Johnson County, Kansas. That claim was dismissed without prejudice in September 2015. Rockies Express believes Michels' claims are without merit and plans to continue to vigorously contest all of the claims in this matter.
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 $4.3 million and $4.8 million at September 30, 2016 and December 31, 2015, respectively.
TMID
Casper Plant, EPA Notice of Violation
In August 2011, the 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 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 EPA concerning settlement of this matter in April 2013 and received additional settlement communications from the EPA and Department of Justice beginning in July 2014. Settlement negotiations are continuing, including the expected 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.

23



Trailblazer
Pipeline Integrity Management Program
In 2014 and 2015, Trailblazer conducted 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. Such repair or replacement will likely occur over a period of years, depending upon final assessment of corrosion growth rates and the remediation and repair plan implemented by Trailblazer. Trailblazer is currently operating at less than its current maximum allowable operating 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 32 excavation digs at an aggregate cost of approximately $1.3 million 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 continuing to develop 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. In 2016, Trailblazer intends to replace approximately 8 miles of pipe, install additional ground beds, and continue remediating areas with external control anomalies at an estimated cost of $21.5 million. 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 incurred 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 an annual $1.5 million deductible. During the nine months ended September 30, 2016, TEP received contributions of $5.3 million from TD related to the indemnity.
14. Reporting Segments
Our operations are located in the United States. We are organized into three reporting segments: (1) Crude Oil Transportation & Logistics, (2) Natural Gas Transportation & Logistics, and (3) Processing & Logistics.
Crude Oil Transportation & Logistics
The Crude Oil Transportation & Logistics segment is engaged in the ownership and operation of the Pony Express System, which is a FERC-regulated crude oil pipeline serving the Bakken Shale, Denver-Julesburg and Powder River Basins, 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 the second quarter of 2015.
Natural Gas Transportation & Logistics
The Natural Gas Transportation & Logistics segment is engaged in the 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. The Natural Gas Transportation & Logistics segment includes our 25% membership interest in Rockies Express effective May 6, 2016, as discussed in Note 3Acquisitions.
Processing & Logistics
The Processing & Logistics segment is engaged in the 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 and the transportation of NGLs.
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 facility, public company costs, and equity-based compensation expense.

24



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 consider Adjusted EBITDA our primary segment performance measure as we believe it is the most meaningful measure to assess our financial condition and results of operations as a public entity. We define Adjusted EBITDA, a non-GAAP measure, as net income excluding the impact of interest, income taxes, depreciation and amortization, non-cash income or loss related to derivative instruments, non-cash long-term compensation expense, impairment losses, gains or losses on asset or business disposals or acquisitions, gains or losses on the repurchase, redemption or early retirement of debt, and earnings from unconsolidated investments, but including the impact of distributions from unconsolidated investments.
The following tables set forth our segment information for the periods indicated:
 
Three Months Ended September 30, 2016
 
Three Months Ended September 30, 2015
Revenue:
Total
Revenue
 
Inter-
Segment
 
External
Revenue
 
Total
Revenue
 
Inter-
Segment
 
External
Revenue
 
(in thousands)
Crude Oil Transportation & Logistics
$
95,826

 
$

 
$
95,826

 
$
83,272

 
$

 
$
83,272

Natural Gas Transportation & Logistics
33,812

 
(1,427
)
 
32,385

 
33,636

 
(1,346
)
 
32,290

Processing & Logistics
23,914

 

 
23,914

 
22,606

 

 
22,606

Corporate and Other

 

 

 

 

 

Total Revenue
$
153,552

 
$
(1,427
)
 
$
152,125

 
$
139,514

 
$
(1,346
)
 
$
138,168

 
Nine Months Ended September 30, 2016
 
Nine Months Ended September 30, 2015
Revenue:
Total
Revenue
 
Inter-
Segment
 
External
Revenue
 
Total
Revenue
 
Inter-
Segment
 
External
Revenue
 
(in thousands)
Crude Oil Transportation & Logistics
$
283,868

 
$

 
$
283,868

 
$
208,872

 
$

 
$
208,872

Natural Gas Transportation & Logistics
94,949

 
(4,192
)
 
90,757

 
98,215

 
(4,036
)
 
94,179

Processing & Logistics
69,836

 

 
69,836

 
82,762

 

 
82,762

Corporate and Other

 

 

 

 

 

Total Revenue
$
448,653

 
$
(4,192
)
 
$
444,461

 
$
389,849

 
$
(4,036
)
 
$
385,813


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Three Months Ended September 30, 2016
 
Three Months Ended September 30, 2015
Adjusted EBITDA:
Total
Adjusted
EBITDA
 
Inter-
Segment
 
External
Adjusted
EBITDA
 
Total
Adjusted
EBITDA
 
Inter-
Segment
 
External
Adjusted
EBITDA
 
(in thousands)
Crude Oil Transportation & Logistics
$
65,431

 
$
1,346

 
$
66,777

 
$
47,526

 
$
1,346

 
$
48,872

Natural Gas Transportation & Logistics
41,253

 
(1,427
)
 
39,826

 
15,983

 
(1,346
)
 
14,637

Processing & Logistics
3,210

 
81

 
3,291

 
3,046

 

 
3,046

Corporate and Other
(1,368
)
 

 
(1,368
)
 
(703
)
 

 
(703
)
Reconciliation to Net Income:
 
 
 
 
 
 
 
 
 
 
 
Add:
 
 
 
 
 
 
 
 
 
 
 
Equity in earnings of unconsolidated investment
 
 
 
 
12,066

 
 
 
 
 

Less:
 
 
 
 
 
 
 
 
 
 
 
Interest expense, net of noncontrolling interest
 
 
 
 
(10,907
)
 
 
 
 
 
(3,872
)
Depreciation and amortization expense, net of noncontrolling interest
 
 
 
 
(21,102
)
 
 
 
 
 
(18,826
)
Distributions from unconsolidated investment
 
 
 
 
(21,804
)
 
 
 
 
 

Non-cash (loss) gain related to derivative instruments, net of noncontrolling interest
 
 
 
 
(4,410
)
 
 
 
 
 
259

Non-cash compensation expense
 
 
 
 
(1,635
)
 
 
 
 
 
(734
)
Net income attributable to partners
 
 
 
 
$
60,734

 
 
 
 
 
$
42,679


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Nine Months Ended September 30, 2016
 
Nine Months Ended September 30, 2015
Adjusted EBITDA:
Total
Adjusted
EBITDA
 
Inter-
Segment
 
External
Adjusted
EBITDA
 
Total
Adjusted
EBITDA
 
Inter-
Segment
 
External
Adjusted
EBITDA
 
(in thousands)
Crude Oil Transportation & Logistics
$
195,732

 
$
4,037

 
$
199,769

 
$
119,352

 
$
4,036

 
$
123,388

Natural Gas Transportation & Logistics
104,168

 
(4,192
)
 
99,976

 
51,820

 
(4,036
)
 
47,784

Processing & Logistics
10,110

 
155

 
10,265

 
18,841

 

 
18,841

Corporate and Other
(3,809
)
 

 
(3,809
)
 
(2,374
)
 

 
(2,374
)
Reconciliation to Net Income:
 
 
 
 
 
 
 
 
 
 
 
Add:
 
 
 
 
 
 
 
 
 
 
 
Equity in earnings of unconsolidated investment
 
 
 
 
35,387

 
 
 
 
 

Non-cash loss allocated to noncontrolling interest
 
 
 
 

 
 
 
 
 
9,377

Less:
 
 
 
 
 
 
 
 
 
 
 
Interest expense, net of noncontrolling interest
 
 
 
 
(27,639
)
 
 
 
 
 
(11,205
)
Depreciation and amortization expense, net of noncontrolling interest
 
 
 
 
(64,909
)
 
 
 
 
 
(57,661
)
Distributions from unconsolidated investment
 
 
 
 
(51,460
)
 
 
 
 
 

Non-cash gain related to derivative instruments, net of noncontrolling interest
 
 
 
 
5,391

 
 
 
 
 
218

Non-cash compensation expense
 
 
 
 
(4,270
)
 
 
 
 
 
(3,988
)
Non-cash loss from asset sales
 
 
 
 
(1,849
)
 
 
 
 
 
(4,483
)
Net income attributable to partners


 


 
$
196,852

 


 


 
$
119,897

 
Nine Months Ended September 30,
Capital Expenditures:
2016
 
2015
 
(in thousands)
Crude Oil Transportation & Logistics
$
25,985

 
$
40,579

Natural Gas Transportation & Logistics
11,146

 
10,858

Processing & Logistics
8,121

 
13,709

Corporate and Other

 

Total capital expenditures
$
45,252

 
$
65,146