Tallgrass Energy Partners, LP - FORM 10-Q - August 6, 2014

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
 
 
 FORM 10-Q
 
 
 
 (Mark One)
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 2014
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
 
4,922
 
46-1972941
(State or other Jurisdiction of Incorporation or Organization)
 
(Primary Standard Industrial Classification Code Number)
 
(IRS Employer
Identification Number)
4200 W. 115th Street, Suite 350
Leawood, Kansas 66211
(913) 928-6060
(Address, including zip code, and telephone number, including area code, of Registrant’s principal executive offices)
George E. Rider
4200 W. 115th Street, Suite 350
Leawood, Kansas 66211
(913) 928-6060
(Address, including zip code, and telephone number, including area code, of Agent for service)
 
 
 
 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
 
¨
  
Accelerated filer
 
¨
 
 
 
 
Non-accelerated filer
 
x  (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  ý
On August 1, 2014, the Registrant had 32,735,140 Common Units, 16,200,000 Subordinated Units, and 834,391 General Partner Units outstanding.



TALLGRASS ENERGY PARTNERS, LP
TABLE OF CONTENTS
 
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Glossary of Common Industry and Measurement Terms
Base Gas (or Cushion Gas): The volume of gas that is intended as permanent inventory in a storage reservoir to maintain adequate pressure and deliverability rates.
BBtu: One billion British Thermal Units.
Bcf: One billion cubic feet.
British Thermal Units or Btus: the amount of heat energy needed to raise the temperature of one pound of water by one degree Fahrenheit.
Condensate: A NGL with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
Delivery point: the point at which product in a pipeline is delivered to the end user.
Dry gas: A gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing.
Dth: A dekatherm, which is a unit of energy equal to 10 therms or one million British thermal units.
End-user markets: The ultimate users and consumers of transported energy products.
FERC: Federal Energy Regulatory Commission.
Firm transportation and storage services: Those services pursuant to which customers receive firm assurances regarding the availability of capacity and deliverability of natural gas on our assets up to a contracted amount at specified receipt and delivery points.
GAAP: Generally accepted accounting principles in the United States of America.
GHGs: Greenhouse gases.
Header system: Networks of medium-to-large-diameter high pressure pipelines that connect local gathering systems to large diameter high pressure long-haul transportation pipelines.
HP: Horsepower.
Interruptible transportation and storage services: Those services pursuant to which customers receive only limited assurances regarding the availability of capacity and deliverability in transportation or storage facilities, as applicable, and pay fees based on their actual utilization of such assets.
Local distribution company or LDC: LDCs are involved in the delivery of natural gas to consumers within a specific geographic area.
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.
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).
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.
PHMSA: The United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration.
Play: A proven geological formation that contains commercial amounts of hydrocarbons.
Receipt point: The point where production is received by or into a gathering system or transportation pipeline.
Reservoir: A porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is characterized by a single natural pressure system.
Residue gas: The natural gas remaining after being processed or treated.
Shale gas: Natural gas produced from organic (black) shale formations.
Tailgate: The point at which processed natural gas and NGLs leave a processing facility for end-user markets.
TBtu: One trillion British Thermal Units.
Tcf: One trillion cubic feet.
Throughput: The volume of natural gas transported or passing through a pipeline, plant, terminal or other facility during a particular period.
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 cushion 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) 
 
June 30, 2014
 
December 31, 2013
 
(in thousands)
ASSETS
 
Current Assets:
 
 
 
Cash and cash equivalents
$
16

 
$
—

Accounts receivable, net
27,698

 
30,033

Gas imbalances
1,336

 
3,128

Inventories
8,122

 
5,549

Prepayments and other current assets
1,788

 
16,986

Total Current Assets
38,960

 
55,696

Property, plant and equipment, net
660,251

 
657,780

Goodwill
343,288

 
334,715

Intangible asset, net
7,495

 
—

Unconsolidated investment
—

 
1,255

Deferred financing costs
6,273

 
4,512

Deferred charges and other assets
11,048

 
11,299

Total Assets
$
1,067,315

 
$
1,065,257

LIABILITIES AND PARTNERS’ EQUITY
 
 
 
Current Liabilities:
 
 
 
Accounts payable
$
27,940

 
$
60,240

Accounts payable to related parties
3,963

 
7,137

Gas imbalances
4,407

 
3,664

Derivative liabilities at fair value
439

 
184

Accrued taxes
3,871

 
5,520

Accrued other current liabilities
16,988

 
16,748

Total Current Liabilities
57,608

 
93,493

Long-term debt
281,000

 
135,000

Other long-term liabilities and deferred credits
6,933

 
4,572

Total Long-term Liabilities
287,933

 
139,572

Commitments and Contingencies (Note 13)

 

Equity:
 
 
 
Predecessor Equity
—

 
88,251

Common unitholders (24,685,140 and 24,300,000 units issued and outstanding at June 30, 2014 and December 31, 2013)
475,227

 
455,197

Subordinated unitholder (16,200,000 units issued and outstanding at June 30, 2014 and December 31, 2013)
275,554

 
274,666

General partner (834,391 and 826,531 units issued and outstanding at June 30, 2014 and December 31, 2013)
(30,352
)
 
14,078

Total Partners’ Equity
720,429

 
832,192

Noncontrolling interests
$
1,345

 
$
—

Total Equity
$
721,774

 
$
832,192

Total Liabilities and Equity
$
1,067,315

 
$
1,065,257


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


TALLGRASS ENERGY PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(UNAUDITED)
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
(in thousands, except per unit amounts)
Revenues:
 
 
 
 
 
 
 
Natural gas liquids sales
$
36,329


$
31,690


$
85,236


$
65,091

Natural gas sales
2,713


4,248


7,521


4,698

Transportation services
30,569


30,909


64,673


60,527

Processing and other revenues
7,709


2,500


14,669


4,719

Total Revenues
77,320

 
69,347

 
172,099

 
135,035

Operating Costs and Expenses:
 
 
 
 
 
 
 
Cost of sales and transportation services
41,172


35,257


93,240


66,443

Operations and maintenance
10,055


9,229


18,068


16,592

Depreciation and amortization
8,768


9,332


16,320


18,722

General and administrative
7,124


6,517


13,773


12,544

Taxes, other than income taxes
1,639


1,663


3,595


3,709

Total Operating Costs and Expenses
68,758

 
61,998

 
144,996

 
118,010

Operating Income
8,562

 
7,349

 
27,103

 
17,025

Other (Expense) Income:
 
 
 
 
 
 
 
Interest (expense) income, net
(2,140
)

(3,495
)

(3,433
)

(9,059
)
Gain on remeasurement of unconsolidated investment
9,388

 
—

 
9,388

 
—

Loss on extinguishment of debt
—


(17,526
)

—


(17,526
)
Equity in earnings of unconsolidated investment
273


—


717


—

Other income, net
729


445


1,669


801

Total Other Expense
8,250

 
(20,576
)
 
8,341

 
(25,784
)
Net Income (Loss)
16,812

 
(13,227
)
 
35,444

 
(8,759
)
Net loss attributable to noncontrolling interests
55


—


55


—

Net Income (loss) attributable to partners
$
16,867

 
$
(13,227
)
 
$
35,499

 
$
(8,759
)
Total comprehensive income attributable to partners
$
16,867

 
$
(13,227
)
 
$
35,499

 
$
(8,759
)
Allocation of income (loss) to the limited partners:

 

 

 

Net income (loss) attributable to partners
$
16,867

 
$
(13,227
)
 
$
35,499

 
$
(8,759
)
Predecessor operations interest in net loss (income)
—

 
1,500

 
(5,732
)
 
2,103

Net income (loss) attributable to partners
16,867

 
(11,727
)
 
29,767

 
(6,656
)
Net income attributable to partners prior to May 17, 2013
—

 
(1,911
)
 
—

 
(6,982
)
Net income (loss) attributable to partners subsequent to May 17, 2013
16,867

 
(13,638
)
 
29,767

 
(13,638
)
General partner interest in net (income) loss subsequent to May 17, 2013
(1,096
)
 
273

 
(1,477
)
 
273

Common and subordinated unitholders' interest in net income (loss) subsequent to May 17, 2013
$
15,771

 
$
(13,365
)
 
$
28,290

 
$
(13,365
)
Basic net income (loss) per common and subordinated unit
$
0.39

 
$
(0.33
)
 
$
0.70

 
$
(0.33
)
Diluted net income (loss) per common and subordinated unit
$
0.38

 
$
(0.33
)
 
$
0.68

 
$
(0.33
)
Basic average number of common and subordinated units outstanding
40,885

 
40,246

 
40,694

 
40,246

Diluted average number of common and subordinated units outstanding
41,905

 
40,246

 
41,624

 
40,246


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)
 
Six Months Ended June 30,
 
2014
 
2013
 
(in thousands)
Cash Flows from Operating Activities:
 
 
 
Net income (loss)
$
35,444

 
$
(8,759
)
Adjustments to reconcile net income (loss) to net cash flows from operating activities:

 

Depreciation and amortization
16,956

 
19,940

Gain on remeasurement of unconsolidated investment
(9,388
)
 
—

Loss on extinguishment of debt
—

 
17,526

Noncash compensation expense
2,249

 
85

Changes in components of working capital:

 

Accounts receivable and other
4,144

 
18,683

Gas imbalances
831

 
2,517

Inventories
(867
)
 
(2,592
)
Accounts payable and accrued liabilities
(17,249
)
 
(9,484
)
Other operating, net
2,833

 
(5,233
)
Net Cash Provided by Operating Activities
34,953

 
32,683

Cash Flows from Investing Activities:
 
 
 
Acquisition of Trailblazer
(150,000
)
 
—

Capital expenditures
(19,851
)
 
(20,724
)
Acquisition of additional equity interests in Water Solutions
(7,600
)
 
—

Unconsolidated investment
(1,999
)
 
—

Other investing, net
358

 
(341
)
Net Cash Used in Investing Activities
(179,092
)
 
(21,065
)
Cash Flows from Financing Activities:
 
 
 
Borrowings under revolving credit facility
146,000

 
224,000

Contribution from TD
27,488

 
—

Distributions to unitholders
(26,770
)
 
—

Reimbursement of stock compensation expense from TD
2,392

 
—

Distributions to Predecessor Member, net
(2,893
)
 
(1,215
)
Payments for deferred financing costs
(2,325
)
 
(4,988
)
Repayment of debt assumed from TD
—

 
(400,000
)
Proceeds from initial public offering, net of offering costs
—

 
290,706

Distributions to Member, net
—

 
(118,538
)
Other financing, net
263

 
(308
)
Net Cash Provided by (Used in) Financing Activities
144,155

 
(10,343
)
Net Change in Cash and Cash Equivalents
16

 
1,275

Cash and Cash Equivalents, beginning of period
—

 
—

Cash and Cash Equivalents, end of period
$
16

 
$
1,275

 
 
 
 
Supplemental Disclosures:
 
 
 
Cash payments for interest
$
2,239

 
$
561

Schedule of Noncash Investing and Financing Activities:


 


Increase in accrual for payment of property, plant and equipment
$
—

 
$
484

Receivable for unreimbursed stock compensation from TD
$
413

 
$
—

Fair value of TIGT and TMID assets contributed by TD
$
—

 
$
1,027,127

Fair value of TIGT and TMID liabilities contributed by TD
$
—

 
$
(566,849
)

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


TALLGRASS ENERGY PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(UNAUDITED)
 
 
Predecessor Equity
 
Limited Partners
 
General Partner
 
Total Partners’ Equity
 
Noncontrolling interests
 
Total Equity
 
 
Common
 
Subordinated
 
 
 
Balance at January 1, 2014
$
88,251

 
$
455,197

 
$
274,666

 
$
14,078

 
$
832,192

 
$
—

 
$
832,192

Net Income
5,732

 
17,034

 
11,256

 
1,477

 
35,499

 
(55
)
 
35,444

Distributions to Predecessor Member, net
(2,893
)
 
—

 
—

 
—

 
(2,893
)
 
—

 
(2,893
)
Acquisition of Trailblazer
(91,090
)
 
14,023

 
—

 
—

 
(77,067
)
 
—

 
(77,067
)
Excess purchase price over carrying value of acquired interests in Trailblazer
—

 
—

 
—

 
(72,933
)
 
(72,933
)
 
—

 
(72,933
)
Acquisition of Water Solutions
—

 
—

 
—

 
—

 
—

 
1,400

 
1,400

Contribution from Tallgrass Development, LP
—

 
—

 
—

 
27,488

 
27,488

 
—

 
27,488

Issuance of general partner units
—

 
—

 
—

 
263

 
263

 
—

 
263

Distributions to unitholders
—

 
(15,677
)
 
(10,368
)
 
(725
)
 
(26,770
)
 
—

 
(26,770
)
Noncash compensation expense
—

 
4,650

 
—

 
—

 
4,650

 
—

 
4,650

Balance at June 30, 2014
$
—

 
$
475,227

 
$
275,554

 
$
(30,352
)
 
$
720,429

 
$
1,345

 
$
721,774


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


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 Delaware limited partnership formed in February 2013.
On May 17, 2013, TEP closed its initial public offering (“IPO”). The 14,600,000 common units held by the public constitute approximately 36% of TEP’s aggregate outstanding common and subordinated units and approximately 35% of TEP’s aggregate outstanding common, subordinated and general partner units at June 30, 2014. Tallgrass Development, LP (“TD”) held 10,085,140 common units and 16,200,000 subordinated units at June 30, 2014, which comprised approximately 64% of TEP’s aggregate outstanding common and subordinated units and approximately 63% of TEP’s aggregate outstanding common, subordinated and general partner units. In addition, 834,391 general partner units, representing a 2% general partner interest in TEP at June 30, 2014, and all of the incentive distribution rights (“IDRs”) are held by Tallgrass MLP GP, LLC (the “general partner”). In connection with the IPO, TEP entered into a revised partnership agreement on May 17, 2013. The amended and restated partnership agreement requires TEP to distribute its available cash on a quarterly basis, subject to certain terms and conditions, beginning with the quarter ending June 30, 2013. For additional information, see Note 9 – Partnership Equity and Distributions. As discussed in Note 15 – Subsequent Events, TEP closed on a public offering of an additional 8,050,000 common units on July 25, 2014.
The term “TEP Predecessor” refers to Tallgrass Energy Partners Predecessor, which is comprised of the businesses described below that were owned by TD, from November 13, 2012 through the completion of the IPO on May 17, 2013.
The businesses included in the TEP Predecessor consist of:
•
Tallgrass Interstate Gas Transmission, LLC (“TIGT”), which owns an interstate gas pipeline and storage system (the “TIGT System”) that is regulated by the FERC. TIGT currently has approximately 4,645 miles of varying diameter natural gas transmission lines in Colorado, Kansas, Missouri, Nebraska and Wyoming.
•
Tallgrass Midstream, LLC (“TMID”), which owns and operates one treating and two processing plants in Wyoming.
The term "Predecessor Entity" refers to Trailblazer Pipeline Company LLC ("Trailblazer"), which TEP acquired on April 1, 2014, as further discussed in Note 2 – Summary of Significant Accounting Policies. Financial results for all prior periods have been recast to reflect the operations of the Predecessor Entity.
2.
Summary of Significant Accounting Policies
Basis of Presentation
These unaudited condensed consolidated financial statements and related notes for the three and six months ended June 30, 2014 and 2013 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 disclosures required by GAAP for annual periods. The unaudited condensed consolidated financial statements for the three and six months ended June 30, 2014 and 2013 include all normal, recurring adjustments and disclosures that we believe are necessary for a fair presentation of the results for the interim periods. In this report, the Financial Accounting Standards Board is referred to as the FASB and the FASB Accounting Standards Codification is referred to as the Codification or ASC. Certain prior period amounts have been reclassified to conform to the current presentation.
TEP’s financial results for the three and six months ended June 30, 2014 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2014. These unaudited condensed consolidated financial statements should be read in conjunction with TEP’s audited consolidated financial statements and notes thereto included in its Annual Report on Form 10-K for the year ended December 31, 2013 (“2013 Form 10-K”) filed with the United States Securities and Exchange Commission (the “SEC”) on March 11, 2014.

5


The accompanying consolidated financial statements of TEP include historical cost-basis accounts of the assets of TEP Predecessor, contributed to TEP by TD in connection with the IPO, for the periods prior to May 17, 2013, the closing date of TEP’s IPO, as well as Trailblazer for the periods prior to April 1, 2014, the date TEP acquired Trailblazer from TD, and include charges from TD for direct costs and allocations of indirect corporate overhead. Management believes that the allocation methods are reasonable, and that the allocations are representative of costs that would have been incurred on a stand-alone basis. Both TEP and TEP Predecessor are considered “entities under common control” as defined under GAAP and, as such, the transfers between the entities of the assets and liabilities has been recorded by TEP at historical cost. TEP, or the Partnership, as used herein refers to the consolidated financial results and operations for TEP Predecessor from its inception through its contribution to TEP and thereafter.
As further discussed in Note 3 – Business Combinations, TEP closed the acquisition of Trailblazer on April 1, 2014. As the acquisition of Trailblazer is considered a transaction between entities under common control, and a change in reporting entity, the financial information presented for prior periods has been recast to include Trailblazer for all periods presented.
The condensed consolidated financial statements include the accounts of TEP and its subsidiaries. Significant intra-entity items have been eliminated in the presentation. Net equity distributions of the TEP Predecessor and the Predecessor Entity included in the Consolidated Statements of Cash Flows represent transfers of cash as a result of TD’s centralized cash management systems prior to May 17, 2013, and prior to April 1, 2014 for Trailblazer, under which cash balances were swept daily and recorded as loans from the subsidiaries to TD. These loans were then periodically recorded as equity distributions.
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 TEP’s 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 Issued But Not Yet Effective
Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers (Topic 606)”
In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, entities must apply a five step process to (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract.
The amendments in ASU 2014-09 are effective for public entities for annual reporting periods beginning after December 15, 2016, and for interim periods within that reporting period. Early application is not permitted. The adoption of ASU 2014-09 is not expected to have a material impact on TEP's financial position and results of operations.

6


ASU No. 2014-12, "Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period"
In June 2014, The FASB issued ASU No. 2014-12, Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. ASU 2014-12 provides explicit guidance on accounting for share-based payments requiring a specific performance target to be achieved in order for employees to become eligible to vest in the awards when that performance target may be achieved after the requisite service period for the award. The ASU requires that such performance targets be treated as a performance condition, and should not be reflected in the estimate of the grant-date fair value of the award. Instead, compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved. ASU 2014-12 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption is permitted. The adoption of ASU 2014-12 is not expected to have a material impact on TEP's financial position and results of operations.
3.
Business Combinations
On April 1, 2014, TEP closed the acquisition of Trailblazer from a wholly owned subsidiary of TD for total consideration valued at approximately $164 million, consisting of $150 million in cash and the issuance of 385,140 common units (valued at approximately $14 million based on the March 31, 2014 closing price of TEP’s common units). On that same date, the general partner contributed additional capital in the amount of approximately $263,000 in exchange for the issuance of 7,860 general partner units in order to maintain its 2% general partner interest. The acquisition of Trailblazer represents a change in reporting entity and a transaction between entities under common control. The excess purchase price over the net book value of Trailblazer's assets and liabilities was accounted for as a deemed distribution as discussed further in Note 9 – Partnership Equity and Distributions.

7


Historical Financial Information
The results of our acquisition of Trailblazer are included in the consolidated balance sheets as of June 30, 2014 and December 31, 2013. The following table presents the previously reported December 31, 2013 consolidated balance sheet, adjusted for the acquisition of Trailblazer from TD:
 
 
As of December 31, 2013
 
 
TEP
 
Consolidate Trailblazer Pipeline Company LLC
 
TEP (as currently reported)
 
 
(in thousands)
ASSETS
 
 
 
 
 
 
Current Assets:
 
 
 
 
 
 
Accounts receivable, net
 
$
27,615

 
$
2,418

 
$
30,033

Gas imbalances
 
2,598

 
530

 
3,128

Inventories
 
5,148

 
401

 
5,549

Prepayments and other current assets
 
16,986

 
—

 
16,986

Total Current Assets
 
52,347

 
3,349

 
55,696

Property, plant and equipment, net
 
594,911

 
62,869

 
657,780

Goodwill
 
304,474

 
30,241

 
334,715

Unconsolidated investment
 
1,255

 
—

 
1,255

Deferred financing costs
 
4,512

 
—

 
4,512

Deferred charges and other assets
 
10,299

 
1,000

 
11,299

Total Assets
 
$
967,798

 
$
97,459

 
$
1,065,257

LIABILITIES AND PARTNERS’ EQUITY
 

 

 
 
Current Liabilities:
 

 

 
 
Accounts payable
 
$
54,621

 
$
5,619

 
$
60,240

Accounts payable to related parties
 
7,134

 
3

 
7,137

Gas imbalances
 
3,142

 
522

 
3,664

Derivative liabilities at fair value
 
184

 
—

 
184

Accrued taxes
 
4,427

 
1,093

 
5,520

Accrued other current liabilities
 
14,777

 
1,971

 
16,748

Total Current Liabilities
 
84,285

 
9,208

 
93,493

Long-term debt
 
135,000

 
—

 
135,000

Other long-term liabilities and deferred credits
 
4,572

 
—

 
4,572

Total Long-term Liabilities
 
139,572

 
—

 
139,572

Partners’ Equity:
 
 
 
 
 
 
Net Equity
 
743,941

 
88,251

 
832,192

Total Partners’ Equity
 
743,941

 
88,251

 
832,192

Total Liabilities and Partners’ Equity
 
$
967,798

 
$
97,459

 
$
1,065,257


8


The results of our acquisition of Trailblazer are included in the condensed consolidated statements of income for the three and six months ended June 30, 2014 and 2013. The following tables present the previously reported condensed consolidated statements of income for the three and six months ended June 30, 2013, adjusted for the acquisition of Trailblazer from TD:
 
 
Three Months Ended June 30, 2013
 
 
TEP
 
Consolidate Trailblazer Pipeline Company LLC
 
TEP (as currently reported)
 
 
(in thousands)
Revenues:
 
 
 
 
 
 
Natural gas liquids sales
 
$
31,690

 
$
—

 
$
31,690

Natural gas sales
 
3,888

 
360

 
4,248

Transportation services
 
25,324

 
5,585

 
30,909

Processing and other revenues
 
2,500

 
—

 
2,500

Total Revenues
 
63,402

 
5,945

 
69,347

Operating Costs and Expenses:
 

 

 
 
Cost of sales and transportation services
 
32,358

 
2,899

 
35,257

Operations and maintenance
 
8,305

 
924

 
9,229

Depreciation and amortization
 
7,436

 
1,896

 
9,332

General and administrative
 
5,039

 
1,478

 
6,517

Taxes, other than income taxes
 
1,394

 
269

 
1,663

Total Operating Costs and Expenses
 
54,532

 
7,466

 
61,998

Operating Income (Loss)
 
8,870

 
(1,521
)
 
7,349

Other (Expense) Income:
 

 

 
 
Interest (expense) income, net
 
(3,500
)
 
5

 
(3,495
)
Loss on extinguishment of debt
 
(17,526
)
 
—

 
(17,526
)
Other income, net
 
429

 
16

 
445

Total Other (Expense) Income
 
(20,597
)
 
21

 
(20,576
)
Net Loss
 
$
(11,727
)
 
$
(1,500
)
 
$
(13,227
)

9


 
 
Six Months Ended June 30, 2013
 
 
TEP
 
Consolidate Trailblazer Pipeline Company LLC
 
TEP (as currently reported)
 
 
(in thousands)
Revenues:
 
 
 
 
 
 
Natural gas liquids sales
 
$
65,091

 
$
—

 
$
65,091

Natural gas sales
 
4,189

 
509

 
4,698

Transportation services
 
49,661

 
10,866

 
60,527

Processing and other revenues
 
4,719

 
—

 
4,719

Total Revenues
 
123,660

 
11,375

 
135,035

Operating Costs and Expenses:
 

 

 
 
Cost of sales and transportation services
 
61,828

 
4,615

 
66,443

Operations and maintenance
 
14,840

 
1,752

 
16,592

Depreciation and amortization
 
14,982

 
3,740

 
18,722

General and administrative
 
9,673

 
2,871

 
12,544

Taxes, other than income taxes
 
3,171

 
538

 
3,709

Total Operating Costs and Expenses
 
104,494

 
13,516

 
118,010

Operating Income (Loss)
 
19,166

 
(2,141
)
 
17,025

Other (Expense) Income:
 

 

 
 
Interest (expense) income, net
 
(9,064
)
 
5

 
(9,059
)
Loss on extinguishment of debt
 
(17,526
)
 
—

 
(17,526
)
Other income, net
 
768

 
33

 
801

Total Other (Expense) Income
 
(25,822
)
 
38

 
(25,784
)
Net Loss
 
$
(6,656
)
 
$
(2,103
)
 
$
(8,759
)
Formation of BNN Water Solutions, LLC
On November 26, 2013, TEP, through its wholly-owned subsidiary Tallgrass Energy Investments, LLC (“TEI”), entered into a joint venture agreement with BNN Energy LLC (“BNN”) to form Grasslands Water Services I, LLC (“GWSI”). GWSI subsequently built and began operating an intrastate water pipeline in Colorado. TEP accounted for its 50% equity interest in GWSI as an equity method investment. On May 13, 2014, TEI entered into a contribution agreement with BNN and several other parties to form a new entity known as BNN Water Solutions, LLC (“Water Solutions”). Under the terms of the contribution agreement, TEI agreed to contribute its existing 50% interest in GWSI, along with $7.6 million cash, in exchange for an 80% equity interest in Water Solutions. As part of the transaction, GWSI was renamed BNN Redtail, LLC (“Redtail”), became a subsidiary of Water Solutions, and issued preferred equity interests to TEI. Among the assets contributed by BNN and the other parties to the transaction were the other 50% interest in GWSI and a 100% equity interest in Alpha Reclaim Technology, LLC (“Alpha”), a company which sources treated wastewater from municipalities. Alpha is wholly-owned by Redtail.
Upon closing of the transaction, TEP obtained a controlling financial interest in Water Solutions and accordingly has accounted for the transaction as a step acquisition under ASC 805. On the acquisition date, TEP remeasured its previously held 50% equity interest in GWSI to its fair value of $11.9 million, recognized a gain of $9.4 million, and consolidated Water Solutions. The 20% equity interest in Water Solutions held by noncontrolling interests was recorded at its acquisition date fair value of $1.4 million. The fair values of the previously held equity interest and the noncontrolling interest were determined using a discounted cash flow based on forecasted cash flows for the business. These fair value measurements are based on significant inputs that are not observable in the market and thus represent fair value measurements categorized within Level 3 of the fair value hierarchy under ASC 820.

10


The following represents the fair value of assets acquired and liabilities assumed at May 13, 2014:
Accounts receivable
$
790

 
Property, plant and equipment
4,100

 
Intangible assets
8,200

(1) 
Accounts payable and accrued liabilities
(134
)
 
Distribution payable
(634
)
 
Net identifiable assets acquired
12,322

 
Goodwill
8,573

 
Net assets acquired
$
20,895

 
(1) 
The $8.2 million intangible asset acquired represents a major customer contract and is subject to amortization over the remaining contract term (approximately 1.6 years). Amortization of $0.7 million was recorded during the period from May 13, 2014 to June 30, 2014.
At June 30, 2014, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. TEP is in the process of obtaining additional information to identify and measure all assets acquired and liabilities assumed in the acquisition within the measurement period. Such provisional amounts will be adjusted if necessary to reflect any new information about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of these amounts.
Actual revenue and net loss attributable to TEP from Water Solutions of $0.9 million and $0.2 million, respectively, was recognized in the accompanying Condensed Consolidated Statements of Income for the period from May 13, 2014 to June 30, 2014.
Pro Forma revenue and net income attributable to TEP for the three and six months ended June 30, 2014 is presented in the following table. No pro forma information is presented for the three and six months ended June 30, 2013 as Water Solutions did not begin commercial operations until the first quarter of 2014.
 
Three Months Ended June 30, 2014
 
Six Months Ended June 30, 2014
 
(in thousands)
Revenue
$
78,084

 
$
174,540

Net income attributable to TEP
$
7,642

 
$
26,541

This unaudited pro forma financial information for TEP is presented as if the acquisition of Water Solutions had been completed on January 1, 2013. 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 Predecessor 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 for the three and six months ended June 30, 2014 to give effect to the following:
(a)
Reduction in net income attributable to TEP to remove equity in earnings of GWSI recorded for the period from January 1, 2014 to May 13, 2014.
(b)
Increase in revenue and net income attributable to TEP to reflect TEP's consolidated 80% equity interest in the operations of GWSI for the period from January 1, 2014 to May 13, 2014.
(c)
Reduction in net income attributable to TEP to remove gain on remeasurement of previously held equity interest in GWSI.

11


Reconciliation of Goodwill
The following table presents a reconciliation of the carrying amount of goodwill by reportable segment for the reporting period:
 
Three Months Ended June 30, 2014
 
Three Months Ended June 30, 2013
 
Gas Transportation and storage
 
Processing
 
Total
 
Gas Transportation and storage
 
Processing
 
Total
 
 
 
(in thousands)
 
 
 
 
 
(in thousands)
 
 
Balance at beginning of period
$
255,558

 
$
79,157

 
$
334,715

 
$
255,100

 
$
78,057

 
$
333,157

Goodwill acquired
—

 
8,573

(1) 
8,573

 
—

 
—

 
—

Balance at end of period
$
255,558

 
$
87,730

 
$
343,288

 
$
255,100

 
$
78,057

 
$
333,157

 
Six Months Ended June 30, 2014
 
Six Months Ended June 30, 2013
 
Gas Transportation and storage
 
Processing
 
Total
 
Gas Transportation and storage
 
Processing
 
Total
 
 
 
(in thousands)
 
 
 
 
 
(in thousands)
 
 
Balance at beginning of period
$
255,558

 
$
79,157

 
$
334,715

 
$
255,100

 
$
78,057

 
$
333,157

Goodwill acquired
—

 
8,573

(1) 
8,573

 
—

 
—

 
—

Balance at end of period
$
255,558

 
$
87,730

 
$
343,288

 
$
255,100

 
$
78,057

 
$
333,157

(1)    The $8.6 million of goodwill was recorded in connection with the acquisition of a controlling interest in Water Solutions on May 13, 2014.
4.
Related Party Transactions
TEP has no employees. Beginning November 13, 2012, TD, through its wholly-owned subsidiary Tallgrass Operations, LLC ("Tallgrass Operations"), provided and charged TEP for all direct and indirect costs of services provided to us or incurred on our behalf including employee labor costs, information technology services, employee health and life benefits, and all other expenses necessary or appropriate to the conduct of our business. TEP recorded these costs on the accrual basis in the period in which TD incurred them. Each of the wholly-owned companies comprising TEP had an agency arrangement with TD under which TD paid costs and expenses incurred by TEP, acted as an agent for TEP, and was reimbursed by TEP for such payments.
On May 17, 2013, in connection with the closing of TEP’s IPO, TEP and its general partner entered into an Omnibus Agreement with TD and certain of its affiliates, including Tallgrass Operations (the “Omnibus Agreement”). The 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.
For the calendar year 2014, TEP’s annual cost reimbursements to TD for costs discussed above, are expected to be $20.4 million, inclusive of costs associated with our acquisition of Trailblazer in April 2014 and our consolidation of Water Solutions in May 2014. TEP also pays a quarterly reimbursement to TD for costs associated with being a public company. The quarterly public company reimbursement was $625,000 for the second quarter of 2014 and TEP currently expects it to remain the same for each subsequent quarter in 2014. However, these reimbursement amounts will be periodically reviewed and adjusted as necessary to continue to reflect reasonable allocation of costs to TEP.
Due to the cash management agreement discussed in Note 2 – Summary of Significant Accounting Policies, intercompany balances at the Predecessor Entity were periodically settled and treated as equity distributions prior to the completion of the IPO on May 17, 2013 and prior to April 1, 2014 for Trailblazer.

12


Totals of transactions with affiliated companies are as follows:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
(in thousands)
Charges to TEP: (1)
 
 
 
 
 
 
 
Operation and maintenance
$
4,608

 
$
4,597

 
$
8,956

 
$
8,716

General and administrative (2)
$
4,305

 
$
6,247

 
$
8,887

 
$
12,200

(1) 
Charges to TEP include directly charged wages and salaries, other compensation and benefits, and shared services.
(2) 
During the three and six months ended June 30, 2014 and 2013, TEP reimbursed TD for general and administrative expenses as discussed above, resulting in allocated amounts for general and administrative costs.
There were no balances with affiliates included in "Accounts receivable" in the Condensed Consolidated Balance Sheets at June 30, 2014 and December 31, 2013. Details of balances with affiliates included in “Accounts payable” in the Condensed Consolidated Balance Sheets are as follows: 
 
June 30, 2014
 
December 31, 2013
 
(in thousands)
Payables to affiliated companies:
 
 
 
Accounts payable to Tallgrass Operations, LLC
$
3,921

 
$
7,106

Accounts payable to Rockies Express Pipeline LLC
42

 
31

Total payables to affiliated companies
$
3,963

 
$
7,137

Balances of gas imbalances with affiliated shippers are as follows:
 
June 30, 2014
 
December 31, 2013
 
(in thousands)
Affiliate gas balance receivables
$
—

 
$
137

Affiliate gas balance payables
$
803

 
$
122

Pursuant to the terms of a Purchase and Sale Agreement dated August 1, 2012, TD, on behalf of its wholly-owned subsidiary, Tallgrass Pony Express Pipeline, LLC (“Pony Express”), is reimbursing TIGT for all costs TIGT incurs with respect to the Pony Express Abandonment, as defined in Note 12 – Regulatory Matters, including, but not limited to, development costs, capital costs and related interest costs associated with the construction of certain gas facilities necessary to maintain existing natural gas service on the TIGT System (the “Replacement Gas Facilities”). The Replacement Gas Facilities are required as part of the Pony Express Abandonment in order for TIGT to continue service to existing customers after having sold approximately 430 miles of natural gas pipeline, and associated rights of way and certain other equipment, to Pony Express in 2013. For more information, see Note 12 – Regulatory Matters.
TIGT’s expenditures for the Replacement Gas Facilities are captured in “Prepayments and other current assets” in the Condensed Consolidated Balance Sheets as they are incurred and interest is accrued until reimbursement takes place (which is typically monthly). During the six months ended June 30, 2014 we received proceeds from TD of $67.1 million and incurred expenditures of $39.2 million. We recognized a contribution of $27.5 million from TD in our Condensed Consolidated Statement of Partners' Capital which represents the difference between the carrying amount of the Replacement Gas Facilities and the proceeds received from TD, and $0.4 million in "Accrued and other current liabilities" related to the timing of cash expenditures and reimbursement from TD. At December 31, 2013, TEP had $17.0 million in “Prepayments and other current assets” related to this project that were cash settled by TD in the first quarter of 2014.

13


5.
Inventory
The components of inventory at June 30, 2014 and December 31, 2013 consisted of the following:
 
June 30, 2014
 
December 31, 2013
 
(in thousands)
Materials and supplies
$
2,187

 
$
2,137

Natural gas liquids
1,210

 
1,009

Gas in underground storage
4,725

 
2,403

Total inventory
$
8,122

 
$
5,549

6.
Property, Plant and Equipment
A summary of net property, plant and equipment by classification is as follows:
 
June 30, 2014
 
December 31, 2013
 
(in thousands)
Natural gas pipelines
$
419,409

 
$
397,287

Processing and treating assets
237,964

 
209,329

General and other
30,606

 
26,076

Construction work in progress
7,843

 
47,352

Accumulated depreciation and amortization
(35,571
)
 
(22,264
)
Total property, plant and equipment, net
$
660,251

 
$
657,780

7.
Risk Management
TEP occasionally enters into derivative contracts with third parties for the purpose of hedging exposures that accompany its normal business activities. TEP’s normal business activities expose it to risks associated with changes in the market price of commodities, including, among others, natural gas. Specifically, the risks associated with changes in the market price of natural gas, include, among others (i) pre-existing or anticipated physical natural gas sales, (ii) natural gas purchases and (iii) natural gas system use and storage. TEP has elected not to apply hedge accounting and changes in the fair value of all derivative contracts are recorded in earnings in the period in which the change occurs.
Fair Value of Derivative Contracts
The following table summarizes the fair values of TEP’s derivative contracts included in the accompanying Condensed Consolidated Balance Sheets: 
 
Balance Sheet
Location
 
June 30, 2014
 
December 31, 2013
 
 
 
(in thousands)
Energy commodity derivative contracts
Current liabilities
 
$
439

 
$
184

TEP had no derivative contracts in asset positions as of June 30, 2014 or December 31, 2013. As of June 30, 2014, the fair value shown for commodity contracts was comprised of derivative volumes for short and long fixed-price swaps totaling 0.6 Bcf and 0.6 Bcf, respectively.

14


Effect of Derivative Contracts on the Income Statement
The following table summarizes the impact of derivative contracts included in the accompanying Condensed Consolidated Statements of Income and Comprehensive Income for the three and six months ended June 30, 2014 and 2013:
 
Location of
gain (loss) recognized
in income on
derivatives
 
Amount of gain (loss) recognized in income on derivatives
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2014
 
2013
 
2014
 
2013
 
 
 
(in thousands)
Derivatives not designated as hedging contracts:
 
 
 
 
 
 
 
 
 
Energy commodity derivative contracts
Natural gas sales
 
$
(106
)
 
$
635

 
$
(458
)
 
$
(284
)
Credit Risk
TEP has counterparty credit risk as a result of its use of derivative contracts. TEP’s counterparties consist of major financial institutions. This concentration of counterparties may impact TEP’s 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.
TEP maintains credit policies that it believes minimize its overall credit risk. These policies include (i) an evaluation of potential counterparties’ financial condition (including credit ratings), (ii) collateral requirements under certain circumstances and (iii) the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty. Based on its policies and exposure, TEP’s management does not currently anticipate a material adverse effect on TEP’s financial position, results of operations, or cash flows as a result of counterparty performance.
TEP’s over-the-counter swaps are entered into with counterparties outside central trading organizations such as a futures, options or stock exchange. These contracts are with financial institutions with investment grade credit ratings. While TEP enters into derivative transactions principally with investment grade counterparties and actively monitors their ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future. As of June 30, 2014, the fair value of TEP’s derivative contracts was a liability, resulting in no credit exposure from TEP’s counterparties as of that date.
In addition, when the market value of TEP’s derivative contracts with specific counterparties exceeds established limits, TEP is required to provide collateral to its counterparties, which may include posting letters of credit or placing cash in margin accounts. Accordingly, entity valuation adjustments are necessary to reflect the effect of TEP’s own credit quality on the fair value of TEP’s net liability position with each counterparty. The methodology to determine this adjustment is consistent with how TEP evaluates counterparty credit risk, taking into account current credit spreads for its comparative industry sector, as well as any change in such spreads since the last measurement date. As of June 30, 2014 and December 31, 2013, TEP did not have any outstanding letters of credit or cash in margin accounts in support of its hedging of commodity price risks associated with the sale of natural gas nor did TEP have margin deposits with counterparties associated with energy commodity contract positions.
Fair Value
Derivative assets and liabilities are measured and reported at fair value. Derivative contracts can be exchange-traded or over-the-counter (“OTC”). Exchange-traded derivative contracts typically fall within Level 1 of the fair value hierarchy if they are traded in an active market. TEP values exchange-traded derivative contracts using quoted market prices for identical securities.
OTC derivatives are valued using models utilizing a variety of inputs including contractual terms and commodity and interest rate curves. The selection of a particular model and particular inputs to value an OTC derivative contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market. TEP uses similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic forwards and swaps, model inputs can generally be verified and model selection does not involve significant management judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy.
Certain OTC derivative contracts trade in less liquid markets with limited pricing information; as such, the determination of fair value for these derivative contracts is inherently more difficult. Such contracts are classified within Level 3 of the fair value hierarchy. The valuations of these less liquid OTC derivatives are typically impacted by Level 1 and/or Level 2 inputs that can be observed in the market, as well as unobservable Level 3 inputs. Use of a different valuation model or different valuation input values could produce a significantly different estimate of fair value. However, derivative contracts valued using inputs unobservable in active markets are generally not material to TEP’s financial statements.

15


When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used.
The following tables summarize the fair value measurements of TEP’s energy commodity derivative contracts in a liability position as of June 30, 2014 and December 31, 2013 based on the fair value hierarchy established by the Codification:
 
 
 
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)
TEP as of June 30, 2014
 
 
 
 
 
 
 
Energy commodity derivative contracts
$
439

 
$
—

 
$
439

 
$
—

TEP as of December 31, 2013
 
 
 
 
 
 
 
Energy commodity derivative contracts
$
184

 
$
—

 
$
184

 
$
—

8.
Long-term Debt
Revolving Credit Facility
TEP has a senior secured revolving credit facility with Barclays Bank PLC, as administrative agent, and a syndicate of lenders (the "Credit Agreement") which will mature on May 17, 2018. On June 25, 2014, TEP and certain of its subsidiaries entered into Amendment No. 1 (the "Amendment") to the Credit Agreement dated as of May 17, 2013. The Amendment modifies certain provisions of the Credit Agreement to, among other things, (i) increase the amount of the revolving facility from $500 million to $850 million, (ii) increase the sublimit for swing line loans to $60 million, (iii) increase the sublimit for letters of credit to $75 million, (iv) increase the accordion feature to allow the Partnership to borrow up to an additional $250 million, subject to the Partnership's receipt of increased or new commitments from lenders and satisfaction of certain other conditions, and (v) reduce the applicable margin for loans by 0.25%.
The following table sets forth the outstanding borrowings, letters of credit issued, and available borrowing capacity under the revolving credit facility as of June 30, 2014 and December 31, 2013:
 
June 30, 2014
 
December 31, 2013
 
(in thousands)
Total capacity under the revolving credit facility
$
850,000

 
$
500,000

Less: Outstanding borrowings under the revolving credit facility
(281,000
)
 
(135,000
)
Less: Letters of credit issued under the revolving credit facility
—

 
(654
)
Available capacity under the revolving credit facility
$
569,000

 
$
364,346

The credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict TEP’s ability (as well as the ability of TEP’s restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions (including distributions from available cash, if a default or event of default under the credit agreement then exists or would result from making such a distribution), change the nature of TEP’s business, engage in certain mergers or make certain investments and acquisitions, enter into non-arms-length transactions with affiliates and designate certain subsidiaries as “Unrestricted Subsidiaries.” Currently, no subsidiaries have been designated as Unrestricted Subsidiaries. In addition, TEP is required to maintain a consolidated leverage ratio of not more than 4.75 to 1.00 (which will be increased to 5.25 to 1.00 for certain measurement periods following the consummation of certain acquisitions) and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of June 30, 2014, TEP is in compliance with the covenants required under the revolving credit facility.
The unused portion of the credit facility is subject to a commitment fee, which was initially 0.375%, and after June 25, 2014, ranges from 0.300% to 0.500%, based on TEP’s total leverage ratio. As of June 30, 2014, the weighted average interest rate on outstanding borrowings was 1.95%.

16


Long-term Debt Allocated from TD
On November 13, 2012, TD entered into a credit agreement with a syndicate of lenders which included a term loan, a delayed draw term loan and a revolving credit facility. Prior to May 17, 2013, the long-term debt held by TD was guaranteed by TIGT and TMID, and $400 million of that debt was expected to be assumed by TEP in connection with the IPO. As such, $400 million of the term loan, along with the corresponding discount and deferred financing costs, was allocated to TEP as of November 13, 2012. The term loan is an obligation of TD and prior to May 17, 2013, was guaranteed by TIGT and TMID.
Upon the closing of the IPO on May 17, 2013, TEP legally assumed the previously allocated $400 million portion of the TD term loan and used a portion of the IPO proceeds, along with borrowings under TEP’s revolving credit agreement, to repay its $400 million portion of the term loan, at which time TIGT and TMID were released as guarantors of the TD debt. TEP recognized a loss on extinguishment of debt of $17.5 million during the year ended December 31, 2013 associated with the portion of deferred financing costs and unamortized discount on the amount of the TD term loan that was allocated to TEP.
Fair Value
The following table sets forth the carrying amount and fair value of TEP’s long-term debt, which is not measured at fair value in the Condensed Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013, 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)
 
 
June 30, 2014
$
—

 
$
281,000

 
$
—

 
$
281,000

 
$
281,000

December 31, 2013
$
—

 
$
135,000

 
$
—

 
$
135,000

 
$
135,000

The long-term debt borrowed under the revolving credit facility is carried at amortized cost. As of June 30, 2014 and December 31, 2013, the fair value approximates the carrying amount for the borrowings under the revolving credit facility using a discounted cash flow analysis. TEP is not aware of any factors that would significantly affect the estimated fair value subsequent to June 30, 2014.
9.
Partnership Equity and Distributions
TEP’s partnership agreement requires TEP to distribute its available cash, as defined below, to unitholders of record on the applicable record date within 45 days after the end of each quarter, beginning with the quarter ended June 30, 2013. TEP’s partnership agreement provides that available cash, each quarter, is first distributed to the common unitholders and the general partner on a pro rata basis until each common unitholder has received $0.2875 per unit, which amount is defined in TEP’s partnership agreement as the minimum quarterly distribution (“MQD”). During the subordination period, defined below, holders of the subordinated units are not entitled to receive a distribution of available cash until each holder of common units has received the MQD, and if the MQD is not paid for any quarter, the cumulative amount of any arrearages in the payment of the MQD from prior quarters.
The following table shows the distributions for the year ended 2013 and six months ended June 30, 2014:
 
 
 
 
Distributions
 
 
 
  
 
 
 
Limited Partners
Common and
Subordinated
 
General Partner
 
 
 
Distributions
per Limited
Partner Unit
 
Three Months Ended
 
Date Paid
 
Incentive
 
2%
 
Total
 
 
 
 
 
 
(in thousands, except per unit amounts)
 
 
 
June 30, 2014
 
August 14, 2014 (1)
 
$
18,596

 
$
758

 
$
330

 
$
19,684

 
$
0.3800

 
March 31, 2014
 
May 14, 2014
 
13,288

 
126

 
274

 
13,688

 
0.3250

 
December 31, 2013
 
February 12, 2014
 
12,757

 
63

 
262

 
13,082

 
0.3150

 
September 30, 2013
 
November 13, 2013
 
12,049

 
—

 
245

 
12,294

 
0.2975

 
June 30, 2013
 
August 13, 2013
 
5,759

 
—

 
118

 
5,877

 
0.1422

(2) 
(1) 
The distribution declared on July 1, 2014 for the second quarter of 2014 is expected to be paid August 14, 2014 subsequent to the date of this Quarterly Report on 48,935,140 common units and subordinated units of record at the close of business on July 30, 2014.

17


(2) 
The distribution declared on July 18, 2013 for the second quarter of 2013 represented a prorated amount of the MQD of $0.2875 per common unit, based upon the number of days between the closing of the IPO on May 17, 2013 to June 30, 2013.
Subordinated Units
All subordinated units are currently held by TD. The principal difference between the common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive a distribution of available cash until the holders of common units have received the MQD (inclusive of any cumulative arrearages of previously unpaid MQD from previous quarters). Furthermore, subordinated unitholders are not entitled to receive arrearages from previous quarterly distributions. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. The subordination period will end, and the subordinated units will convert to common units, on a one-for-one basis, when certain distribution milestones described in the partnership agreement have been met.
Incentive Distribution Rights
As of June 30, 2014, the general partner owns a 2% general partner interest in TEP, which was represented by 834,391 general partner units. As discussed in Note 3 – Business Combinations, in April 2014, in connection with TEP’s acquisition of Trailblazer, the general partner contributed capital in exchange for the issuance of an additional 7,860 general partner units in order to continue to maintain its 2% general partner interest. The general partner also owns all of the IDRs. IDRs represent the right to receive an increasing percentage (13%, 23% and 48%) of quarterly distributions of available cash from operating surplus after the MQD and the target distribution levels have been achieved. The general partner may transfer these rights separately from its general partner interest, subject to restrictions in TEP’s partnership agreement. Under TEP’s partnership agreement, the general partner may at any time contribute additional capital to TEP in order to maintain its 2% general partner interest.
The following discussion related to incentive distributions assumes that TEP’s general partner maintains its 2.0% general partner interest and continues to own all of the IDRs.
If for any quarter:
•
TEP has distributed available cash from operating surplus to all of the common unitholders (and during the subordination period, to the subordinated unitholders) in an amount equal to the MQD for each outstanding unit for such quarter; and
•
TEP has distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in the payment of the MQD to common unitholders;
then, TEP will distribute additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:
•
first, 98% to all unitholders, pro rata, and 2% to TEP’s general partner, until each unitholder receives a total of $0.3048 per unit for that quarter (the “first target distribution”);
•
second, 85% to all unitholders, pro rata, and 15% to TEP’s general partner, until each unitholder receives a total of $0.3536 per unit for that quarter (the “second target distribution”);
•
third, 75% to all unitholders, pro rata, and 25% to TEP’s general partner, until each unitholder receives a total of $0.4313 per unit for that quarter (the “third target distribution”); and
•
thereafter, 50% to all unitholders, pro rata, and 50% to TEP’s general partner.
Definition of Available Cash
Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:
•
less, the amount of cash reserves established by TEP’s general partner to:
•
provide for the proper conduct of TEP’s business (including reserves for future capital expenditures, for anticipated future credit needs subsequent to that quarter, for legal matters and for refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings);
•
comply with applicable law or regulation, any of TEP’s debt instruments or other agreements; or
•
provide funds for distributions to unitholders and to TEP’s general partner for any one or more of the next four quarters (provided that TEP’s general partner may not establish cash reserves for

18


distributions if the effect of the establishment of such reserves will prevent TEP from distributing the MQD on all common units and any cumulative arrearages on such common units for the current quarter);
•
plus, if TEP’s general partner so determines, all or any portion of the cash on hand on the date of distribution of available cash for the quarter, including cash on hand resulting from working capital borrowings made subsequent to the end of such quarter.
Other Distributions
As discussed in Note 2 – Summary of Significant Accounting Policies, prior to May 17, 2013 for TIGT and TMID and prior to April 1, 2014 for Trailblazer, the net amount of transfers for loans made each day through the centralized cash management system, less reimbursement payments under the agency agreement described in Note 4 – Related Party Transactions, was recognized as equity distributions during that time period. During the three and six months ended June 30, 2014, TEP was deemed to have made a noncash, net capital distribution of $72.9 million to the general partner, which represents the excess purchase price over the carrying value of the Trailblazer net assets acquired on April 1, 2014. See Note 3 – Business Combinations for additional information regarding the Trailblazer acquisition. During the period from January 1, 2014 to March 31, 2014, Trailblazer made net distributions to TD of$2.9 million. There were no equity distributions made to TD subsequent to Trailblazer's acquisition by TEP on April 1, 2014.
Net distributions from TEP to TD for the six months ended June 30, 2013 were approximately $119.8 million, respectively, and included the $85.5 million to TD related to the contribution of TIGT and TMID to TEP, the $31.2 million net proceeds from the exercise of the underwriter’s option to purchase additional common units as part of the Offering, and $1.2 million net distributions from Trailblazer to TD.
10.
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.
TEP computes 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.
TEP calculates 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 TEP’s overall net income or other financial results; however, in periods in which aggregate net income exceeds its 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 TEP’s aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the general partner, even though TEP makes distributions on the basis of available cash and not earnings. In periods in which TEP’s aggregate net income does not exceed its 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.
As the IPO was completed on May 17, 2013, no income from the period from January 1, 2013 to May 16, 2013 is allocated to the limited partner units that were issued on May 17, 2013 and all income for such period was allocated to the general partner or predecessor operations. All net income or loss from Trailblazer prior to its acquisition on April 1, 2014 is allocated to predecessor operations in the table below.
The following table illustrates the Partnership’s calculation of net income per common and subordinated unit for the three and six months ended June 30, 2014 and 2013:
 
Three Months Ended June 30, 2014
 
Three Months Ended June 30, 2013
 
Period from April 1, 2013 to May 16, 2013
 
Period from May 17, 2013 to June 30, 2013
 
(in thousands, except per unit amounts)
Net income (loss)
$
16,812

 
$
(13,227
)
 
$
1,722

 
$
(14,949
)
Net loss attributable to noncontrolling interests
55

 
—

 
—

 
—

Net income (loss) attributable to partners
16,867

 
(13,227
)
 
1,722

 
(14,949
)
Predecessor operations interest in net loss
—

 
1,500

 
189

 
1,311

General partner interest in net (income) loss
(1,096
)
 
(1,638
)
 
(1,911
)
 
273

Net income (loss) available to common and subordinated unitholders
$
15,771

 
$
(13,365
)
 
$
—

 
$
(13,365
)
Basic net income (loss) per common and subordinated unit
$
0.39

 
$
(0.33
)
 
 
 
$
(0.33
)
Diluted net income (loss) per common and subordinated unit
$
0.38

 
$
(0.33
)
 
 
 
$
(0.33
)
Basic average number of common and subordinated units outstanding
40,885

 
40,246

 
 
 
40,246

Equity Participation Unit equivalent units
1,020

 
—

 
 
 
—

Diluted average number of common and subordinated units outstanding
41,905

 
40,246

 
 
 
40,246

 
Six Months Ended June 30, 2014
 
Six Months Ended June 30, 2013
 
Period from January 1, 2013 to May 16, 2013
 
Period from May 17, 2013 to June 30, 2013
 
(in thousands, except per unit amounts)
Net income (loss)
$
35,444

 
$
(8,759
)
 
$
6,190

 
$
(14,949
)
Net loss attributable to noncontrolling interests
55

 
—

 
—

 
—

Net income (loss) attributable to partners
35,499

 
(8,759
)
 
6,190

 
(14,949
)
Predecessor operations interest in net (income) loss
(5,732
)
 
2,103

 
792

 
1,311

General partner interest in net (income) loss
(1,477
)
 
(6,709
)
 
(6,982
)
 
273

Net income (loss) available to common and subordinated unitholders
$
28,290

 
$
(13,365
)
 
$
—

 
$
(13,365
)
Basic net income (loss) per common and subordinated unit
$
0.70

 
$
(0.33
)
 
 
 
$
(0.33
)
Diluted net income (loss) per common and subordinated unit
$
0.68

 
$
(0.33
)
 
 
 
$
(0.33
)
Basic average number of common and subordinated units outstanding
40,694

 
40,246

 
 
 
40,246

Equity Participation Unit equivalent units
930

 
—

 
 
 
—

Diluted average number of common and subordinated units outstanding
41,624

 
40,246

 
 
 
40,246

11.
Equity-Based Compensation
Long-term Incentive Plan
Effective May 13, 2013, the general partner adopted a Long-term Incentive Plan (“LTIP”) pursuant to which awards in the form of unrestricted units, restricted units, equity participation units, options, unit appreciation rights or distribution equivalent rights may be granted to employees, consultants, and directors of the general partner and its affiliates who perform services for or on behalf of TEP or its affiliates, including TD. Vesting and forfeiture requirements are at the discretion of the board of directors of the general partner at the time of the grant.

19


The LTIP limits the number of units that may be delivered pursuant to vested awards to 10,000,000 common units. Common units canceled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The plan is administered by the board of directors of TEP’s general partner or a committee thereof, which is referred to as the plan administrator.
The plan administrator may terminate or amend the LTIP at any time with respect to any units for which a grant has not yet been made. The plan administrator also has the right to alter or amend the LTIP or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The LTIP will expire on the earliest of (i) the date common units are no longer available under the plan for grants, (ii) termination of the plan by the plan administrator or (iii) May 13, 2023.
Equity Participation Units
On June 26, 2013, TEP’s general partner approved the grant of up to 1.5 million equity participation units (“EPUs”) for issuance to employees and 177,500 EPUs to certain Section 16 officers under the LTIP. Effective the same date, an aggregate of 1.49 million EPUs were granted to employees and certain Section 16 officers of the general partner and its affiliates. Vesting of the EPUs granted to employees is contingent upon the mainline portion of the Pony Express Project, as defined in Note 15 – Subsequent Events, being placed into service and will generally occur in two parts, with one-third vesting on the later of the Pony Express Project in-service date or May 13, 2015, and the remaining two-thirds vesting on the later of the Pony Express Project in-service date or May 13, 2017. If the Pony Express Project has not been placed in service by May 13, 2018, the EPUs will expire and no vesting of the EPUs will occur. Beginning in the second quarter of 2014, new EPUs granted will vest in two parts, with one-third vesting on the later of the Pony Express Project in-service date or two years from issuance, and the remaining two-thirds vesting on the later of the Pony Express Project in-service date or four years from issuance.
The EPU grants under the LTIP plan are measured at their grant date fair value. The EPUs granted are non-participating with respect to distributions, therefore the grant date fair value is discounted from the grant date fair value of TEP’s common units for the present value of the expected future distributions during the vesting period. Total equity-based compensation cost related to the EPU grants of approximately $2.5 million and $4.7 million was recognized during the three and six months ended June 30, 2014. Of the total compensation cost, $1.3 million and $2.2 million was recognized as compensation expense at TEP for the three and six months ended June 30, 2014 and the remainder was allocated to TD. Total equity-based compensation cost related to the EPU grants of approximately $85,000 was recognized during the three and six months ended June 30, 2013. As of June 30, 2014, $17.9 million of total compensation cost related to non-vested EPUs is expected to be recognized over a weighted average period of 2.4 years, a portion of which will be charged to TD.
The following table summarizes the changes in the EPUs outstanding for the three and six months ended June 30, 2014:
 
Three Months Ended June 30, 2014
 
Three Months Ended June 30, 2013
 
Shares
 
Weighted Average
Grant Date Fair Value
 
Shares
 
Weighted Average
Grant Date Fair Value
Beginning of period
1,486,750

 
$
17.67

 
—

 
$
—

Granted
111,000

 
31.63

 
1,490,000

 
17.49

Forfeited
(30,250
)
 
(17.62
)
 
—

 
—

End of period
1,567,500

 
$
18.66

 
1,490,000

 
$
17.49

 
Six Months Ended June 30, 2014
 
Six Months Ended June 30, 2013
 
Shares
 
Weighted Average
Grant Date Fair Value
 
Shares
 
Weighted Average
Grant Date Fair Value
Beginning of period
1,474,250

 
$
17.54

 
—

 
$
—

Granted
142,500

 
29.86

 
1,490,000

 
17.49

Forfeited
(49,250
)
 
(17.57
)
 
—

 
—

End of period
1,567,500

 
$
18.66

 
1,490,000

 
$
17.49


20


12.
Regulatory Matters
TIGT
Pony Express Abandonment – FERC Docket CP12-495
On August 6, 2012, TIGT filed an application to: (1) abandon for FERC purposes approximately 432 miles of mainline natural gas pipeline facilities, along with associated rights of way and other related equipment (collectively, the "Pony Express Assets"), and the natural gas service therefrom, by transferring those assets to Pony Express, which will convert the Pony Express Assets into crude oil pipeline facilities; and (2) construct and operate the Replacement Gas Facilities in order to continue service to existing natural gas firm transportation customers following the proposed conversion. This project is referred to as the “Pony Express Abandonment.” The FERC abandonment does not constitute an abandonment for accounting purposes. Pursuant to the terms of the Purchase and Sale Agreement filed with the FERC and cited by the FERC in approving the Pony Express Abandonment, Pony Express is required to reimburse TIGT for the net book value of the Pony Express Assets plus other TIGT incurred costs required to construct the Replacement Gas Facilities and to arrange substitute gas transportation services to certain TIGT shippers.
The Pony Express Abandonment and completion of the Pony Express Project by Pony Express will re-deploy existing pipeline assets to meet the growing market need to transport oil supplies from the Bakken Shale while at the same time continuing to operate TIGT’s natural gas transportation facilities to meet all current and expected needs of its natural gas customers. By a FERC order issued September 12, 2013, TIGT was granted authorization to abandon the Pony Express Assets and construct the Replacement Gas Facilities. On October 7, 2013 TIGT commenced the mobilization of personnel and equipment for the construction of the Replacement Gas Facilities necessary to complete the Pony Express Abandonment to continue service to existing TIGT customers. In December 2013, TIGT removed the Pony Express Assets from gas service and sold those assets to Pony Express. Additional phases of the Pony Express Abandonment are expected to be completed during the third quarter of 2014. On May 1, 2014, TIGT commenced commercial service through all of the Replacement Gas Facilities, with the exception of Units 3 and 4 at the Tescott Compressor Station. Service through Units 3 and 4 at the Tescott Compressor Station commenced on May 30, 2014.
Trailblazer
2013 Rate Case Filing - Docket No. RP13-1031
On July 1, 2013, Trailblazer made a rate filing with the FERC pursuant to Section 4 of the Natural Gas Act in Docket No. RP13-1031. In this filing, Trailblazer proposed an overall cost of service of $25.7 million, an increase of the base rates, rolled-in base and fuel rates, an overall rate of return of 10.94% and new depreciation rates. On July 31, 2013, the FERC issued an order accepting Trailblazer’s filing and suspending the filed tariff rates, subject to refund, for the full statutorily permitted five-month suspension period and setting certain issues for hearing. The FERC resolved the non-rate aspects of Trailblazer’s rate case in an order dated December 30, 2013.
In conjunction with this filing for rolled-in fuel rates, Trailblazer elected to not seek recovery of unrecovered fuel costs incurred prior to January 1, 2014. Consequently, Trailblazer has recognized expenses related to unrecovered fuel costs of $578,000 for the period from November 13, 2012 to December 31, 2012, $6.0 million for period from January 1, 2012 to November 12, 2012 and $8.4 million during the year ended December 31, 2013.
On January 22, 2014, Trailblazer, FERC’s Trial Staff, and the active parties in the pipeline’s general rate case finalized a settlement in principle resolving the pending rate issues, including: (i) establishing transportation rates, as well as fuel and lost and unaccounted for charges; (ii) providing a limited profit sharing arrangement for certain revenues earned from interruptible and short-term firm transport; and (iii) setting the minimum and maximum time that can elapse before Trailblazer’s next rate case at the FERC. Trailblazer filed a motion with the FERC’s Chief Administrative Law Judge to accept the settlement rates on an interim basis (“Interim Rates”) while the participants finalized a definitive settlement. The Chief Administrative Law Judge accepted the Interim Rates effective February 1, 2014. On February 24, 2014, Trailblazer filed an uncontested offer of settlement (“Stipulation and Agreement”) among active party shippers. The Stipulation and Agreement established the Interim Rates as final settlement rates effective February 1, 2014, subject to the issuance of refunds to certain shippers for January 2014 transportation services and revised fuel and lost and unaccounted for rates, effective July 1, 2014. On March 11, 2014, the Presiding Administrative Law Judge certified the Stipulation and Agreement. On May 29, 2014, the FERC approved the Stipulation and Agreement. On June 30, 2014, Trailblazer filed tariff sheets to implement the Stipulation and Agreement effective July 1, 2014. Estimated refunds have been reserved from revenues recorded in January 2014. On July 1, 2014, Trailblazer submitted refunds to its customers for amounts collected in excess of amounts that would have been collected under the Settlement Rates, with interest, and on July 18, 2014, filed a report of refunds with the FERC. On July 25, 2014, the FERC accepted the tariff sheets with the requested effective date of July 1, 2014.

21


Other Regulatory Matters
There are currently no proceedings challenging the rates of Trailblazer. Regulators, as well as shippers on Trailblazer, do have rights, under circumstances prescribed by applicable regulations, to challenge the rates Trailblazer charges. Trailblazer can provide no assurance that current rates will remain unchallenged. Any successful challenge could have a material, adverse effect on Trailblazer’s future earnings and cash flows.
13.
Legal and Environmental Matters
Legal
In addition to the matters discussed below, TEP is a defendant in various lawsuits arising from the day-to-day operations of its business. Although no assurance can be given, TEP believes, based on its experiences to date, that the ultimate resolution of such routine items will not have a material adverse impact on its business, financial position, results of operations or cash flows.
TEP has evaluated claims in accordance with the accounting guidance for contingencies that it deems both probable and reasonably estimable and, accordingly, has aggregate reserves for legal claims of approximately $0.6 million and $0.3 million as of June 30, 2014 and December 31, 2013, respectively.
TIGT
Prairie Horizon
On July 3, 2014, Prairie Horizon Agri-Energy LLC ("Prairie Horizon") filed an action in the District Court of Phillips County, Kansas against TIGT seeking damages from an alleged intrusion of foreign material and oil from TIGT into Prairie Horizon's ethanol plant. Prairie Horizon asserts that this intrusion caused substantial damage to Prairie Horizon's ethanol production facilities and resulted in corresponding business income losses. Prairie Horizon also claims that the intrusion was a violation of TIGT's FERC Gas Tariff. Prairie Horizon alleges that it has suffered damages in the amount of approximately $2.0 million. TIGT believes Prairie Horizon's claims are without merit and plans to vigorously contest all of the claims in this matter.
System Failures
On May 4, 2013 and on June 13, 2013, a failure occurred on two separate segments of the TIGT pipeline system; one in Kimball County, Nebraska and one in Goshen County, Wyoming. Both failures resulted in the release of natural gas. Both lines were promptly brought back into service and neither failure caused any known injuries, fatalities, fires or evacuations. The costs to repair or replace the damaged section in Kimball County, Nebraska were not material. In February 2014, TEP communicated to PHMSA that TEP’s investigation of the pipeline involved in the Kimball County failure is complete and TEP intends to restore pressure to full maximum allowable operating pressure. TEP is currently scheduled to start hydrostatic testing the pipeline related to the Goshen County failure in the third quarter of 2014 as required by the Corrective Action Order received from PHMSA. TEP currently expects the cost of remaining remediation activities related to the Goshen County failure to approximate $0.8 million.
Environmental
TEP is 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. TEP believes that compliance with these laws will not have a material adverse impact on its 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 TEP to incur significant costs. TEP has environmental accruals of $5.2 million and $5.0 million at June 30, 2014 and December 31, 2013, respectively.
TMID
Casper Plant, U.S. EPA Notice of Violation
In August 2011, the U.S. EPA and the WDEQ conducted an inspection of the Leak Detection and Repair (“LDAR”) Program at the Casper Gas Plant in Wyoming. In September 2011, TMID received a letter from the U.S. EPA alleging violations of the Standards of Performance of Equipment Leaks for Onshore Natural Gas Processing Plant requirements under the Clean Air Act. TMID received a letter from the U.S. EPA concerning settlement of this matter in April 2013 and received an additional settlement communication from the U.S. EPA and Department of Justice in July 2014. Settlement negotiations are continuing, including attempted resolution of more recently identified LDAR issues.

22


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 TEP has requested that the portion of the site attributable to TEP be delisted from the National Priorities List.
14.
Reporting Segments
TEP’s operations are located in the United States and are organized into two reporting segments: (1) Gas Transportation and Storage, and (2) Processing.
Gas Transportation and Storage
The Gas Transportation and Storage segment is engaged in ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities that provide services to on-system customers (such as third-party LDCs), industrial users and other shippers. As discussed in Note 2 – Summary of Significant Accounting Policies, results for prior periods have been recast to reflect the operations of Trailblazer.
Processing
The Processing segment is engaged in ownership and operation of natural gas processing, treating and fractionation facilities that produce NGLs and residue gas that is sold in local wholesale markets or delivered into pipelines for transportation to additional end markets, as well as water business services provided primarily to the oil and gas exploration and production industry.
Corporate and Other
Corporate and Other includes corporate overhead costs incurred subsequent to the IPO on May 17, 2013 that are not directly associated with the operations of TEP’s reportable segments, such as interest and fees associated with TEP’s revolving credit facility, public company costs reimbursed to TD, and equity-based compensation expense.
These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for their respective operations.
TEP considers Adjusted EBITDA as its primary segment performance measure as TEP believes it is the most meaningful measure to assess TEP’s financial condition and results of operations as a public entity. Adjusted EBITDA, a non-GAAP measure, is defined 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.

23


The following tables set forth TEP’s segment information for the periods indicated:
 
Three Months Ended June 30, 2014
 
Three Months Ended June 30, 2013
 
Total
Revenue
 
Inter-
Segment
 
External
Revenue
 
Total
Revenue
 
Inter-
Segment
 
External
Revenue
 
 
 
(in thousands)
 
 
 
 
 
(in thousands)
 
 
Gas transportation and storage
$
32,610

 
$
—

 
$
32,610

 
$
33,834

 
$
(199
)
 
$
33,635

Processing
44,710

 
—

 
44,710

 
35,712

 
—

 
35,712

Corporate and other
—

 
—

 
—

 
—

 
—

 
—

Total revenue
$
77,320

 
$
—

 
$
77,320

 
$
69,546

 
$
(199
)
 
$
69,347

 
Six Months Ended June 30, 2014
 
Six Months Ended June 30, 2013
 
Total
Revenue
 
Inter-
Segment
 
External
Revenue
 
Total
Revenue
 
Inter-
Segment
 
External
Revenue
 
 
 
(in thousands)
 
 
 
 
 
(in thousands)
 
 
Gas transportation and storage
$
70,986

 
$
—

 
$
70,986

 
$
62,861

 
$
(370
)
 
$
62,491

Processing
101,113

 
—

 
101,113

 
72,544

 
—

 
72,544

Corporate and other
—

 
—

 
—

 
—

 
—

 
—

Total revenue
$
172,099

 
$
—

 
$
172,099

 
$
135,405

 
$
(370
)
 
$
135,035

 
Three Months Ended June 30, 2014
 
Three Months Ended June 30, 2013
 
Total
Adjusted
EBITDA
 
Inter-
Segment
 
External
Adjusted
EBITDA
 
Total
Adjusted
EBITDA
 
Inter-
Segment
 
External
Adjusted
EBITDA
 
(in thousands)
 
(in thousands)
Gas transportation and storage
$
15,066

 
$
—

 
$
15,066

 
$
11,434

 
$
(199
)
 
$
11,235

Processing
5,511

 
—

 
5,511

 
5,236

 
199

 
5,435

Corporate and other
(625
)
 
—

 
(625
)
 
(307
)
 
—

 
(307
)
Reconciliation to Net Income:
 
 
 
 
 
 
 
 
 
 
 
Interest expense, net
 
 
 
 
2,140

 
 
 
 
 
3,495

Depreciation and amortization expense
 
 
 
 
8,622

 
 
 
 
 
9,332

Loss on extinguishment of debt
 
 
 
 
—

 
 
 
 
 
17,526

Non-cash gain related to derivative instruments
 
 
 
 
(96
)
 
 
 
 
 
(848
)
Non-cash compensation expense
 
 
 
 
1,308

 
 
 
 
 
85

Distributions from unconsolidated investment
 
 
 
 
772

 
 
 
 
 
—

Equity in earnings of unconsolidated investment
 
 
 
 
(273
)
 
 
 
 
 
—

Gain on remeasurement of unconsolidated investment
 
 
 
 
(9,388
)
 
 
 
 
 
—

Net Income (Loss)
 
 
 
 
$
16,867

 
 
 
 
 
$
(13,227
)

24


 
Six Months Ended June 30, 2014
 
Six Months Ended June 30, 2013
 
Total
Adjusted
EBITDA
 
Inter-
Segment
 
External
Adjusted
EBITDA
 
Total
Adjusted
EBITDA
 
Inter-
Segment
 
External
Adjusted
EBITDA
 
(in thousands)
 
(in thousands)
Gas transportation and storage
$
34,928

 
$
—

 
$
34,928

 
$
24,941

 
$
(370
)
 
$
24,571

Processing
15,107

 
—

 
15,107

 
12,070

 
370

 
12,440

Corporate and other
(1,250
)
 
—

 
(1,250
)
 
(307
)
 
—

 
(307
)
Reconciliation to Net Income:
 
 
 
 
 
 
 
 
 
 
 
Interest expense, net
 
 
 
 
3,433

 
 
 
 
 
9,059

Depreciation and amortization expense
 
 
 
 
16,174

 
 
 
 
 
18,722

Loss on extinguishment of debt
 
 
 
 
—

 
 
 
 
 
17,526

Non-cash loss related to derivative instruments
 
 
 
 
255

 
 
 
 
 
71

Non-cash compensation expense
 
 
 
 
2,249

 
 
 
 
 
85

Distributions from unconsolidated investment
 
 
 
 
1,280

 
 
 
 
 
—

Equity in earnings of unconsolidated investment
 
 
 
 
(717
)
 
 
 
 
 
—

Gain on remeasurement of unconsolidated investment
 
 
 
 
(9,388
)
 
 
 
 
 
—

Net Income (Loss)
 
 
 
 
$
35,499

 
 
 
 
 
$
(8,759
)
 
Total Assets
 
June 30, 2014
 
December 31, 2013
 
(in thousands)
Gas transportation and storage
$
717,695

 
$
734,145

Processing
344,064

 
326,599

Corporate and other
5,556

 
4,513

Total assets
$
1,067,315

 
$
1,065,257

15.
Subsequent Events
Prairie Horizon
On July 3, 2014, Prairie Horizon filed an action in the District Court of Phillips County, Kansas against TIGT seeking damages from an alleged intrusion of foreign material and oil from TIGT into Prairie Horizon's ethanol plant. For additional information, see Note 13 – Legal and Environmental Matters.
Potential Acquisition
On July 21, 2014, TEP announced that TD offered TEP the right to purchase a 33.3% interest in Tallgrass Pony Express Pipeline, LLC ("Pony Express") for total consideration of $600 million. The terms of TD's offer provide that TEP's 33.3% equity interest would be structured as preferred units in Pony Express bearing certain cash flow preference rights that will afford TEP first dollar preference on specified cash distributions supported by cash flow occurring on or before September 30, 2015.
Pony Express owns and is developing an oil pipeline project, which we collectively refer to as the Pony Express Project. That project consists of two components that include (i) the conversion of an approximately 430-mile natural gas pipeline and the construction of an approximately 260-mile southward pipeline extension that, when complete, will result in an oil pipeline from Guernsey, Wyoming to Cushing, Oklahoma, and (ii) the construction of an approximately 66-mile lateral in Northeast Colorado that will interconnect with the mainline. The project is being completed in stages, with the mainline expected to be placed in service during the third quarter of 2014, while the Northeast Colorado lateral is expected to be in service sometime during the first half of 2015.

25


The offer was received from TD pursuant to a right of first offer that is contained in the Omnibus Agreement that was executed between TEP and TD in connection with TEP’s initial public offering in May 2013. A Conflicts Committee of the Board of Directors of TEP’s general partner, consisting solely of independent directors, has been formed and will be evaluating the offer with assistance from external advisors to be engaged by the Committee. No definitive transaction agreement has been executed at this time and the proposed transaction remains subject to final review, negotiations and approval by the Conflicts Committee and by the board of directors of TEP’s general partner.
Public Offering
On July 25, 2014, TEP sold 8,050,000 common units representing limited partner interests in an underwritten public offering at a price of $41.07 per unit, or $39.74 per unit net of the underwriter's discount, for net proceeds of approximately $319.5 million after deducting the underwriter's discount and estimated offering expenses payable by TEP. TEP intends to use the net proceeds from the offering to fund a portion of the consideration for the potential acquisition from a subsidiary of TD of the 33.3% interest in Pony Express as discussed above. Pending the use of proceeds for such purpose, TEP used the net proceeds of the offering to repay borrowings under TEP’s revolving credit facility with the excess to be used for general partnership purposes.





Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The historical financial statements included in this Quarterly Report reflect the combined results of operations of Tallgrass Interstate Gas Transmission, LLC (“TIGT”) and Tallgrass Midstream, LLC (“TMID”), which we refer to collectively as “our Predecessor.” Historical periods have been recast to reflect the operations of Trailblazer Pipeline Company LLC ("Trailblazer"), which was acquired on April 1, 2014.
In connection with our initial public offering, on May 17, 2013 Tallgrass Development LP (“TD”) contributed to us its equity interests in our Predecessor. The following discussion analyzes the financial condition and results of operations of our Predecessor. In certain circumstances and for ease of reading we discuss the financial results of the Predecessor as being “our” financial results during historic periods, although TIGT and TMID were owned by TD from November 13, 2012 until May 17, 2013 and Trailblazer was owned by TD from November 13, 2012 to March 31, 2014. As used in this Quarterly Report, unless the context otherwise requires, “we,” us,” our,” the “Partnership,” “TEP” and similar terms refer to Tallgrass Energy Partners, LP, together with its consolidated subsidiaries.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited condensed consolidated financial statements and related notes thereto included elsewhere in this Quarterly Report. Additionally, the following discussion should be read in conjunction with the audited financial statements and notes thereto, the related “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the discussion of “Risk Factors” and the discussion of TEP’s “Business” in our Annual Report on Form 10-K for the year ended December 31, 2013 (our “2013 Form 10-K”).
A reference to a “Note” herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1.—Financial Statements. In addition, please read “Cautionary Statement Regarding Forward-Looking Statements” and “Risk Factors” for information regarding certain risks inherent in our business.
Cautionary Statement Regarding Forward-Looking Statements
This Quarterly Report and the documents incorporated by reference herein contain forward-looking statements concerning our operations, economic performance and financial condition. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “could,” “will,” “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this Quarterly Report include our expectations of plans, strategies, objectives, growth and anticipated financial and operational performance, including guidance regarding our and Tallgrass Development’s infrastructure programs, revenue projections, capital expenditures and tax position. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Quarterly Report and our 2013 Form 10-K. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
•
changes in general economic conditions;
•
competitive conditions in our industry;
•
actions taken by third-party operators, processors and transporters;
•
the demand for natural gas processing, storage and transportation services;
•
our ability to successfully implement our business plan;
•
our ability to complete internal growth projects on time and on budget;
•
the price and availability of debt and equity financing;
•
the availability and price of natural gas to the consumer compared to the price of alternative and competing fuels;
•
competition from the same and alternative energy sources;
•
energy efficiency and technology trends;

27


•
operating hazards and other risks incidental to transporting, storing and processing natural gas;
•
natural disasters, weather-related delays, casualty losses and other matters beyond our control;
•
interest rates;
•
labor relations;
•
large customer defaults;
•
changes in tax status;
•
the effects of existing and future laws and governmental regulations;
•
the effects of future litigation; and
•
certain factors discussed elsewhere in this Quarterly Report.
Forward-looking statements speak only as of the date on which they are made. While we may update these statements from time to time, we are not required to do so other than pursuant to the securities laws.
Overview
We are a growth-oriented publicly traded Delaware limited partnership that owns, operates, acquires and develops midstream energy assets in North America. We provide natural gas transportation and storage services for customers in the Rocky Mountain and Midwest regions of the United States through our TIGT System and the Trailblazer Pipeline, and provide processing services for customers in Wyoming through our Casper and Douglas natural gas processing and West Frenchie Draw natural gas treating facilities, which we refer to as the Midstream Facilities.
We intend to leverage our relationship with TD and utilize the significant experience of our management team to execute our growth strategy of acquiring midstream assets from TD and third parties, increasing utilization of our existing assets and expanding our systems through construction of additional assets.
Our reportable business segments are:
•
Gas Transportation and Storage—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities; and
•
Processing—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.
Recent Developments
Potential Acquisition
On July 21, 2014, we announced that TD has offered us the right to purchase a 33.3% interest in Tallgrass Pony Express Pipeline, LLC ("Pony Express") for total consideration of $600 million. The terms of TD's offer provide that our 33.3% equity interest would be structured as preferred units in Pony Express bearing certain cash flow preference rights that will afford us first dollar preference on specified cash distributions supported by cash flow occurring on or before September 30, 2015.
Pony Express owns and is developing an oil pipeline project. That project consists of two components that include (i) the conversion of an approximately 430-mile natural gas pipeline and the construction of an approximately 260-mile southward pipeline extension that, when complete, will result in an oil pipeline from Guernsey, Wyoming to Cushing, Oklahoma, and (ii) the construction of an approximately 66-mile lateral in Northeast Colorado that will interconnect with the mainline. The project is being completed in stages, with the mainline expected to be placed in service during the third quarter of 2014, while the Northeast Colorado Lateral is expected to be in service sometime during the first half of 2015.
The offer was received from TD pursuant to a right of first offer that is contained in the Omnibus Agreement that was executed in connection with our initial public offering in May 2013. A conflicts committee of the board of directors of our general partner, consisting solely of independent directors, has been formed and will be evaluating the offer with assistance from external advisors to be engaged by the committee. No definitive transaction agreement has been executed at this time and the proposed transaction remains subject to final review, negotiations and approval by the conflicts committee and by the board of directors of our general partner.

28


Public Offering
On July 25, 2014, we sold 8,050,000 common units representing limited partner interests in an underwritten public offering at a price of $41.07 per unit, or $39.74 per unit net of the underwriter's discount, for net proceeds of approximately $319.5 million after deducting the underwriter's discount and estimated offering expenses. We intend to use the net proceeds from the offering to fund a portion of the consideration for the potential acquisition from a subsidiary of TD of the 33.3% interest in Pony Express as discussed above. Pending the use of proceeds for such purpose, we used the net proceeds of the offering to repay borrowings under our revolving credit facility with the excess to be used for general partnership purposes.
How We Evaluate Our Operations
We evaluate our results using, among other measures, contract mix and volumes, operating costs and expenses, Adjusted EBITDA and distributable cash flow. Adjusted EBITDA and distributable cash flow are non-GAAP measures and are defined below.
Contract Mix and Volumes
Our results are driven primarily by the volume of natural gas transportation and storage capacity under firm contracts, the volume of natural gas that we process and the fees assessed for such services.
Operating Costs and Expenses
The primary components of our operating costs and expenses that we evaluate include cost of sales and transportation services, operations and maintenance and general and administrative costs. Our operating expenses are driven primarily by expenses related to the operation, maintenance and growth of our asset base.
Adjusted EBITDA and Distributable Cash Flow
Adjusted EBITDA and distributable cash flow are non-GAAP supplemental financial measures that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:
•
our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or, in the case of Adjusted EBITDA, financing methods;
•
the ability of our assets to generate sufficient cash flow to make distributions to our unitholders;
•
our ability to incur and service debt and fund capital expenditures; and
•
the viability of acquisitions and other capital expenditure projects and the returns on investment of various expansion and growth opportunities.
We believe that the presentation of Adjusted EBITDA and distributable cash flow provides useful information to investors in assessing our financial condition and results of operations. Adjusted EBITDA and distributable cash flow should not be considered alternatives to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP, nor should Adjusted EBITDA and distributable cash flow be considered alternatives to available cash, operating surplus, distributions of available cash from operating surplus or other definitions in our partnership agreement. Adjusted EBITDA and distributable cash flow have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities. Additionally, because Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
Non-GAAP Financial Measures
We define Adjusted EBITDA 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. We also use distributable cash flow, which we define as Adjusted EBITDA less cash interest cost and maintenance capital expenditures., to analyze our performance. Neither Adjusted EBITDA nor distributable cash flow will be impacted by changes in working capital balances that are reflected in operating cash flow. Distributable cash flow and Adjusted EBITDA are not presentations made in accordance with GAAP.
The following table presents a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities and a reconciliation of distributable cash flow to net cash provided by operating activities, the most directly comparable GAAP financial measures, for each of the periods indicated:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
(in thousands)
Reconciliation of Adjusted EBITDA to Net Income
 
 
 
 
 
 
 
Net income (loss)
$
16,867

 
$
(13,227
)
 
$
35,499

 
$
(8,759
)
Add:
 
 
 
 
 
 
 
Interest expense, net
2,140

 
3,495

 
3,433

 
9,059

Depreciation and amortization expense
8,622

 
9,332

 
16,174

 
18,722

Loss on extinguishment of debt
—

 
17,526

 
—

 
17,526

Non-cash (gain) loss related to derivative instruments
(96
)
 
(848
)
 
255

 
71

Non-cash compensation expense
1,308

 
85

 
2,249

 
85

Distributions from unconsolidated investment
772

 
—

 
1,280

 
—

Gain on remeasurement of unconsolidated investment
(9,388
)
 
—

 
(9,388
)
 
—

Less:
 
 
 
 
 
 
 
Equity in earnings of unconsolidated investment
(273
)
 
—

 
(717
)
 
—

Adjusted EBITDA
$
19,952

 
$
16,363

 
$
48,785

 
$
36,704

Reconciliation of Adjusted EBITDA and Distributable Cash Flow to Net Cash Provided by Operating Activities
 
 
 
 
 
 
 
Net cash provided by operating activities
$
5,594

 
$
(646
)
 
$
34,953

 
$
32,683

Add:
 
 
 
 
 
 
 
Interest expense, net
2,140

 
3,495

 
3,433

 
9,059

Other, including changes in operating working capital
12,218

 
13,514

 
10,399

 
(5,038
)
Adjusted EBITDA
$
19,952

 
$
16,363

 
$
48,785

 
$
36,704

Less:
 
 
 
 
 
 
 
Maintenance capital expenditures
(2,531
)
 
(3,701
)
 
(3,472
)
 
(3,971
)
Cash interest cost
(1,909
)
 
(763
)
 
(3,082
)
 
(763
)
Distributable Cash Flow attributable to predecessor operations
—

 
1,629

 
(6,637
)
 
394

Distributable Cash Flow
$
15,512

 
$
13,528

 
$
35,594

 
$
32,364

The following table presents a reconciliation of Adjusted EBITDA by segment to segment operating income, the most directly comparable GAAP financial measure, for each of the periods indicated:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
(in thousands)
Reconciliation of Adjusted EBITDA to Operating Income in the Gas Transportation and Storage Segment (1)
 
 
 
 
 
 
 
Operating income
$
8,318

 
$
4,159

 
$
21,284

 
$
8,621

Add:
 
 
 
 
 
 
 
Depreciation and amortization expense
6,115

 
7,676

 
11,720

 
15,446

Non-cash (gain) loss related to derivative instruments
(96
)
 
(848
)
 
255

 
71

Other income
729

 
447

 
1,669

 
803

Segment Adjusted EBITDA
$
15,066

 
$
11,434

 
$
34,928

 
$
24,941

Reconciliation of Adjusted EBITDA to Operating Income in the Processing Segment (1)
 
 
 
 
 
 
 
Operating income
$
2,177

 
$
3,580

 
$
9,318

 
$
8,794

Add:
 
 
 
 
 
 
 
Depreciation and amortization expense
2,507

 
1,656

 
4,454

 
3,276

Distributions from unconsolidated investment
772

 
—

 
1,280

 
—

Net loss attributable to noncontrolling interests
55

 
—

 
55

 
—

Segment Adjusted EBITDA
$
5,511

 
$
5,236

 
$
15,107

 
$
12,070

Total Segment Adjusted EBITDA
$
20,577

 
$
16,670

 
$
50,035

 
$
37,011

Public company costs
(625
)
 
(307
)
 
(1,250
)
 
(307
)
Total Adjusted EBITDA
$
19,952

 
$
16,363

 
$
48,785

 
$
36,704

(1) 
Segment results as presented represent total operating income and Adjusted EBITDA, including intersegment activity, for the Gas Transportation and Storage and Processing segments. For reconciliations to the consolidated financial data, see Note 14 – Reporting Segments to the accompanying consolidated financial statements.





Results of Operations
The following provides a summary of our consolidated results of operations for the periods indicated:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Statements of Operations Data
2014
 
2013
 
2014
 
2013
 
(in thousands, except operating data)
Revenues:
 
 
 
 
 
 
 
Natural gas liquids sales
$
36,329

 
$
31,690

 
$
85,236

 
$
65,091

Natural gas sales
2,713

 
4,248

 
7,521

 
4,698

Transportation services
30,569

 
30,909

 
64,673

 
60,527

Processing and other revenues
7,709

 
2,500

 
14,669

 
4,719

Total Revenues
77,320

 
69,347

 
172,099

 
135,035

Operating Costs and Expenses:
 
 
 
 
 
 
 
Cost of sales and transportation services
41,172

 
35,257

 
93,240

 
66,443

Operations and maintenance
10,055

 
9,229

 
18,068

 
16,592

Depreciation and amortization
8,768

 
9,332

 
16,320

 
18,722

General and administrative
7,124

 
6,517

 
13,773

 
12,544

Taxes, other than income taxes
1,639

 
1,663

 
3,595

 
3,709

Total Operating Costs and Expenses
68,758

 
61,998

 
144,996

 
118,010

Operating Income
8,562

 
7,349

 
27,103

 
17,025

Other (Expense) Income:
 
 
 
 
 
 
 
Interest (expense) income, net
(2,140
)
 
(3,495
)
 
(3,433
)
 
(9,059
)
Gain on remeasurement of unconsolidated investment
9,388

 
—

 
9,388

 
—

Loss on extinguishment of debt
—

 
(17,526
)
 
—

 
(17,526
)
Equity in earnings of unconsolidated investment
273

 
—

 
717

 
—

Other income, net
729

 
445

 
1,669

 
801

Total Other Expense
8,250

 
(20,576
)
 
8,341

 
(25,784
)
Net Income (Loss)
16,812

 
(13,227
)
 
35,444

 
(8,759
)
Net loss attributable to noncontrolling interests
55

 
—

 
55

 
—

Net Income (loss) attributable to partners
16,867

 
(13,227
)
 
35,499

 
(8,759
)
Other Financial Data (1)
 
 
 
 
 
 
 
Adjusted EBITDA
$
19,952

 
$
16,363

 
$
48,785

 
$
36,704

Operating Data
 
 
 
 
 
 
 
Operating Data (Mmcf/d):
 
 
 
 
 
 
 
Transportation firm contracted capacity
1,494

 
1,441

 
1,549

 
1,390

Natural gas processing inlet volumes
136

 
137

 
144

 
132

(1) 
For more information regarding Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly comparable GAAP measure, please see “Non-GAAP Financial Measures” above.
Three Months Ended June 30, 2014 Compared to the Three Months Ended June 30, 2013
Revenues. Total revenues were $77.3 million for the three months ended June 30, 2014, compared to $69.3 million for the three months ended June 30, 2013, which represents an $8.0 million, or 11% increase in total revenues. Revenue in the Gas Transportation and Storage segment decreased $1.2 million, or 4%, while revenues in the Processing segment increased $9.0 million, or 25%.

30


Operating costs and expenses. Operating costs and expenses were $68.8 million for the three months ended June 30, 2014 compared to $62.0 million for the three months ended June 30, 2013, which represents an increase of $6.8 million, or 11%. The increase in operating costs and expenses is a result of increased costs of $10.4 million in the Processing segment primarily driven by higher costs of sales and operations and maintenance expenses, partially offset by decreased costs of $5.4 million in the Gas Transportation and Storage segment primarily driven by decreased cost of sales and operations and maintenance expenses as well as lower depreciation and amortization.
Interest (expense) income. Interest expense of $2.1 million for the three months ended June 30, 2014 was primarily composed of interest and fees associated with TEP’s revolving credit facility. Interest expense of $3.5 million for the three months ended June 30, 2013 primarily represents the interest expense related to the $400 million term loan allocated from TD, which was legally assumed by TEP and repaid upon closing of the IPO on May 17, 2013.
Gain on remeasurement of unconsolidated investment. Gain on remeasurement of unconsolidated investment of $9.4 million for the three months ended June 30, 2014 was related to the remeasurement to fair value of our original 50% equity investment in Grasslands Water Services I, LLC (“GWSI”) prior to TEP's consolidation of the Water Solutions business on May 13, 2014.
Loss on extinguishment of debt. Loss on extinguishment of debt of $17.5 million for the three months ended June 30, 2013 represents the loss associated with the write off of deferred financing costs and unamortized discounts associated with the repayment of debt allocated from TD.
Equity in earnings of unconsolidated investment. Equity in earnings of unconsolidated investment of $0.3 million for the three months ended June 30, 2014 was related to our investment in Grasslands Water Services I, LLC (“GWSI”) prior to TEP's consolidation of the Water Solutions business on May 13, 2014.
Other income (expense), net. Other income for the three months ended June 30, 2014 was $0.7 million compared to $0.4 million for the three months ended June 30, 2013. Other income for the three months ended June 30, 2014 primarily relates to rental income and payments received from certain customers for reimbursement of the capital costs we incurred to connect these customers to our system.
Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013
Revenues. Total revenues were $172.1 million for the six months ended June 30, 2014, compared to $135.0 million for the six months ended June 30, 2013, which represents a $37.1 million, or 27% increase in total revenues. Revenue in the Gas Transportation and Storage segment increased $8.1 million, or 13%, while revenues in the Processing segment increased $28.6 million, or 39%.
Operating costs and expenses. Operating costs and expenses were $145.0 million for the six months ended June 30, 2014 compared to $118.0 million for the six months ended June 30, 2013, which represents an increase of $27.0 million, or 23%. The increase in operating costs and expenses is a result of increased costs of $28.0 million in the Processing segment primarily driven by higher costs of sales and operations and maintenance expenses as well as increased depreciation and amortization primarily related to the Water Solutions assets consolidated during the second quarter of 2014, partially offset by decreased costs of $4.5 million in the Gas Transportation and Storage segment primarily driven by decreased cost of sales and operations and maintenance expenses as well as lower depreciation and amortization.
Interest (expense) income. Interest expense of $3.4 million for the six months ended June 30, 2014 was primarily composed of interest and fees associated with TEP’s revolving credit facility. Interest expense of $9.1 million for the six months ended June 30, 2013 primarily represents the interest expense related to the $400 million term loan allocated from TD, which was legally assumed by TEP and repaid upon closing of the IPO on May 17, 2013.
Gain on remeasurement of unconsolidated investment. Gain on remeasurement of unconsolidated investment of $9.4 million for the six months ended June 30, 2014 was related to the remeasurement to fair value of our original 50% equity investment in Grasslands Water Services I, LLC (“GWSI”) prior to TEP's consolidation of the Water Solutions business on May 13, 2014.
Loss on extinguishment of debt. Loss on extinguishment of debt of $17.5 million for the six months ended June 30, 2013 represents the loss associated with the write off of deferred financing costs and unamortized discounts associated with the repayment of debt allocated from TD.
Equity in earnings of unconsolidated investment. Equity in earnings of unconsolidated investment of $0.7 million for the six months ended June 30, 2014 was related to our investment in GWSI prior to TEP's consolidation of the Water Solutions business on May 13, 2014.

31


Other income (expense), net. Other income for the six months ended June 30, 2014 was $1.7 million compared to $0.8 million for the six months ended June 30, 2013. Other income for the six months ended June 30, 2014 primarily relates to rental income and payments received from certain customers for reimbursement of the capital costs we incurred to connect these customers to our system.
The following provides a summary of our Gas Transportation and Storage segment results of operations for the periods indicated:
Segment Financial Data - Gas Transportation and Storage (1)
Three Months Ended June 30,
 
Six Months Ended June 30,
2014
 
2013
 
2014
 
2013
 
(in thousands)
Revenues:
 
 
 
 
 
 
 
Natural gas sales
$
2,022

 
$
2,721

 
$
6,138

 
$
1,951

Transportation services
30,569

 
31,108

 
64,673

 
60,897

Processing and other revenues
19

 
6

 
175

 
13

Total revenues
32,610

 
33,835

 
70,986

 
62,861

Operating costs and expenses:
 
 
 
 
 
 
 
Cost of sales and transportation services
5,781

 
7,835

 
13,470

 
11,747

Operations and maintenance
6,648

 
7,316

 
12,697

 
13,127

Depreciation and amortization
6,115

 
7,676

 
11,720

 
15,446

General and administrative
4,191

 
5,233

 
8,383

 
10,369

Taxes, other than income taxes
1,557

 
1,616

 
3,432

 
3,551

Total operating costs and expenses
24,292

 
29,676

 
49,702

 
54,240

Operating income
$
8,318

 
$
4,159

 
$
21,284

 
$
8,621

Segment Adjusted EBITDA
$
15,066

 
$
11,434

 
$
34,928

 
$
24,941

(1) 
Segment results as presented represent total revenue and Adjusted EBITDA, including intersegment activity. For reconciliations to the consolidated financial data, see Note 14 – Reporting Segments to the accompanying consolidated financial statements.
Three Months Ended June 30, 2014 Compared to the Three Months Ended June 30, 2013
Revenues. Gas Transportation and Storage segment revenues were $32.6 million for the three months ended June 30, 2014, compared to $33.8 million for the three months ended June 30, 2013, which represents a $1.2 million, or 4% decrease in segment revenues. The decrease in segment revenues was driven by a decrease of $0.7 million in natural gas sales as a result of a noncash mark-to-market loss on derivatives used to hedge future purchases and sales of natural gas in our storage facility and a decrease of $0.5 million in transportation services revenue primarily driven by decreased fuel reimbursements.
Operating costs and expenses. Operating costs and expenses in the Gas Transportation and Storage segment were $24.3 million for the three months ended June 30, 2014 compared to $29.7 million for the three months ended June 30, 2013, which represents a decrease of $5.4 million, or 18%.
Cost of sales and transportation services decreased $2.1 million, or 26%, in the three months ended June 30, 2014 when compared to the same period in the prior year, primarily driven by decreased fuel cost of $1.9 million in 2014 as a result of the Trailblazer rate case settlement.
Operations and maintenance costs decreased $0.7 million, or 9%, in the three months ended June 30, 2014 when compared to the same period in the prior year, primarily driven by the timing of pipeline integrity projects.
Depreciation and amortization decreased $1.6 million, or 20%, in the three months ended June 30, 2014 when compared to the same period in the prior year, primarily driven by the sale of the Pony Express Assets in the fourth quarter of 2013 and the decreased depreciation rates included in the Trailblazer rate case settlement in the second quarter of 2014.
General and administrative costs decreased $1.0 million, or 20%, in the three months ended June 30, 2014 when compared to the same period in the prior year, primarily due to the decrease in costs allocated to Trailblazer by TEP in periods subsequent to our acquisition on April 1, 2014 from the costs allocated by TD prior to April 1, 2014.

32


Taxes, other than income taxes, decreased $0.1 million, or 4%, in the three months ended June 30, 2014 when compared to the same period in the prior year, primarily driven by lower property taxes as a result of successful appeals with state taxing authorities on the assessed value of property.
Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013
Revenues. Gas Transportation and Storage segment revenues were $71.0 million for the six months ended June 30, 2014, compared to $62.9 million for the six months ended June 30, 2013, which represents a $8.1 million, or 13% increase in segment revenues. The increase in segment revenues was primarily driven by a $4.2 million increase in natural gas sales driven by higher prices and volumes, partially offset by a mark-to-market loss on derivatives used to hedge future purchases and sales of natural gas in our storage facility and a $3.8 million increase in transportation services revenue driven by increased volumes at Trailblazer and fuel reimbursements at TIGT.
Operating costs and expenses. Operating costs and expenses in the Gas Transportation and Storage segment were $49.7 million for the six months ended June 30, 2014 compared to $54.2 million for the six months ended June 30, 2013, which represents a decrease of $4.5 million, or 8%.
Cost of sales and transportation services increased $1.7 million, or 15%, in the six months ended June 30, 2014 when compared to the same period in the prior year, primarily driven by increased fuel recovery cost of $2.7 million at TIGT due to weather and throughput volumes and increased fuel reimbursement cost of $2.0 million, partially offset by decreased fuel cost of $3.2 million in 2014 as a result of the Trailblazer rate case settlement.
Operations and maintenance costs decreased $0.4 million, or 3%, in the six months ended June 30, 2014 when compared to the same period in the prior year, primarily driven by the timing of pipeline integrity projects.
Depreciation and amortization decreased $3.7 million, or 24%, in the six months ended June 30, 2014 when compared to the same period in the prior year, primarily driven by the sale of the Pony Express Assets in the fourth quarter of 2013 and the decreased depreciation rates included in the Trailblazer rate case settlement in the second quarter of 2014.
General and administrative costs decreased $2.0 million, or 19%, in the six months ended June 30, 2014 when compared to the same period in the prior year, primarily due to the decrease in costs allocated to Trailblazer by TEP in periods subsequent to our acquisition on April 1, 2014 from the costs allocated by TD prior to April 1, 2014.
Taxes, other than income taxes, decreased $0.1 million, or 3%, in the six months ended June 30, 2014 when compared to the same period in the prior year, primarily driven by lower property taxes as a result of successful appeals with state taxing authorities on the assessed value of property.

33


The following provides a summary of our Processing segment results of operations for the periods indicated:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Segment Financial Data - Processing (1)
2014
 
2013
 
2014
 
2013
 
(in thousands)
Revenues:
 
 
 
 
 
 
 
Natural gas liquids sales
$
36,329

 
$
31,690

 
$
85,236

 
$
65,091

Natural gas sales
691

 
1,527

 
1,383

 
2,747

Processing and other revenues
7,690

 
2,494

 
14,494

 
4,706

Total revenues
44,710

 
35,711

 
101,113

 
72,544

Operating costs and expenses:
 
 
 
 
 
 
 
Cost of sales and transportation services
35,391

 
27,621

 
79,770

 
55,066

Operations and maintenance
3,407

 
1,913

 
5,371

 
3,465

Depreciation and amortization
2,653

 
1,656

 
4,600

 
3,276

General and administrative
1,000

 
894

 
1,891

 
1,785

Taxes, other than income taxes
82

 
47

 
163

 
158

Total operating costs and expenses
42,533

 
32,131

 
91,795

 
63,750

Operating income
$
2,177

 
$
3,580

 
$
9,318

 
$
8,794

Segment Adjusted EBITDA
$
5,511

 
$
5,236

 
$
15,107

 
$
12,070

(1) 
Segment results as presented represent total revenue and Adjusted EBITDA, including intersegment activity. For reconciliations to the consolidated financial data, see Note 14 – Reporting Segments to the accompanying consolidated financial statements.
Three Months Ended June 30, 2014 Compared to the Three Months Ended June 30, 2013
Revenues. Processing segment revenues were $44.7 million for the three months ended June 30, 2014, compared to $35.7 million for the three months ended June 30, 2013, which represents a $9.0 million, or 25% increase in segment revenues. The increase in segment revenues was primarily due to a $4.6 million increase in NGL sales driven by a 23% increase in average NGL prices, a $4.3 million increase in processing fees driven by the conversion of two significant customers from percent of proceeds contracts to fee based contracts, and revenue of $0.9 million from Water Solutions, which was consolidated in May 2014. These increases were partially offset by decreased natural gas sales of $0.8 million due to lower volumes.
Operating costs and expenses. Operating costs and expenses in the Processing segment were $42.5 million for the three months ended June 30, 2014 compared to $32.1 million for the three months ended June 30, 2013, which represents an increase of $10.4 million, or 32%.
Cost of sales and transportation services increased $7.8 million, or 28%, in the three months ended June 30, 2014 when compared to the same period in the prior year, primarily driven by an increase of $8.1 million in NGL producer settlements as a result of increased volumes processed under contracts converted to fee based as discussed above and a 23% increase in average NGL prices, as well as $0.9 million of off-spec fees incurred during the quarter, partially offset by a $1.2 million decrease in fuel expenses.
Operations and maintenance costs increased $1.5 million, or 78%, in the three months ended June 30, 2014 when compared to the same period in the prior year, primarily driven by $0.7 million higher costs in the second quarter of 2014 due to scheduled plant maintenance, $0.4 million in environmental reserves recorded in the second quarter of 2014, and $0.3 million of operations and maintenance costs attributable to the consolidation of the Water Solutions business on May 13, 2014.
Depreciation and amortization increased $1.0 million, or 60%, in the three months ended June 30, 2014 when compared to the same period in the prior year, primarily driven by depreciation and amortization of $0.7 million from the Water Solutions fixed and intangible assets acquired in May 2014 and $0.3 million from asset additions as a result of expansion activities that were substantially completed in the third quarter of 2013.
General and administrative costs increased $0.1 million, or 12%, in the three months ended June 30, 2014 when compared to the same period in the prior year, primarily driven by costs associated with Water Solutions.
Taxes, other than income taxes, in the three months ended June 30, 2014 were consistent with those incurred during the same period in the prior year.

34


Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013
Revenues. Processing segment revenues were $101.1 million for the six months ended June 30, 2014, compared to $72.5 million for the six months ended June 30, 2013, which represents a $28.6 million, or 39% increase in segment revenues. The increase in segment revenues was primarily due to a $20.1 million increase in NGL sales driven by increased volumes processed and a 28% increase in average NGL prices, an $8.9 million increase in processing fees driven by the conversion of two significant customers from percent of proceeds contracts to fee based contracts, and revenue of $0.9 million from Water Solutions, which was consolidated in May 2014. These increases were partially offset by decreased natural gas sales of $1.4 million due to lower volumes.
Operating costs and expenses. Operating costs and expenses in the Processing segment were $91.8 million for the six months ended June 30, 2014 compared to $63.8 million for the six months ended June 30, 2013, which represents an increase of $28.0 million, or 44%.
Cost of sales and transportation services increased $24.7 million, or 45%, in the six months ended June 30, 2014 when compared to the same period in the prior year, primarily driven by an increase of $26.3 million in NGL producer settlements as a result of increased volumes processed under contracts converted to fee based as discussed above and a 28% increase in average NGL prices, as well as $1.2 million of off-spec fees, partially offset by a $1.9 million decrease in fuel expenses.
Operations and maintenance costs increased $1.9 million, or 55%, in the six months ended June 30, 2014 when compared to the same period in the prior year, primarily driven by $0.7 million higher costs in the second quarter of 2014 due to scheduled plant maintenance, $0.4 million in environmental reserves recorded in the second quarter of 2014, and $0.3 million of operations and maintenance costs attributable to the consolidation of the Water Solutions business on May 13, 2014.
Depreciation and amortization increased $1.3 million, or 40%, in the six months ended June 30, 2014 when compared to the same period in the prior year, primarily driven by depreciation and amortization of $0.7 million from the Water Solutions fixed and intangible assets acquired in May 2014 and $0.6 million from asset additions as a result of expansion activities that were substantially completed in the third quarter of 2013.
General and administrative costs increased $0.1 million, or 6%, in the six months ended June 30, 2014 when compared to the same period in the prior year, primarily driven by costs associated with Water Solutions.
Taxes, other than income taxes, in the six months ended June 30, 2014 were consistent with those incurred during the same period in the prior year.
Liquidity and Capital Resources Overview
Our primary sources of liquidity for the three months ended June 30, 2014 were borrowings under our revolving credit facility and cash generated from operations. We expect our sources of liquidity in the future to include:
•
cash generated from our operations;
•
borrowing capacity available under our revolving credit facility; and
•
future issuances of additional partnership units and debt securities.
We believe that cash on hand, cash generated from operations and availability under our credit facility will be adequate to meet our operating needs, our planned short-term capital and debt service requirements and our planned cash distributions to unitholders. We believe that future internal growth projects or potential acquisitions will be funded primarily through a combination of borrowings under our credit facility and issuances of debt and equity securities.
Our total liquidity as of June 30, 2014 and December 31, 2013 was as follows:
 
June 30, 2014
 
December 31, 2013
 
(in thousands)
Cash on hand
$
16

 
$
—

Total capacity under the revolving credit facility
850,000

 
500,000

Less: Outstanding borrowings under the revolving credit facility
(281,000
)
 
(135,000
)
Less: Letters of credit issued under the revolving credit facility
—

 
(654
)
Available capacity under the revolving credit facility
569,000

 
364,346

Total liquidity
$
569,016

 
$
364,346

Revolving Credit Facility
We have a senior secured revolving credit facility with Barclays Bank PLC, as administrative agent, and a syndicate of lenders (the "Credit Agreement") which will mature on May 17, 2018. On June 25, 2014, TEP and certain of its subsidiaries entered into Amendment No. 1 (the "Amendment") to the Credit Agreement dated as of May 17, 2013. The Amendment modifies certain provisions of the Credit Agreement to, among other things, (i) increase the amount of the revolving facility from $500 million to $850 million, (ii) increase the sublimit for swing line loans to $60 million, (iii) increase the sublimit for letters of credit to $75 million, (iv) increase the accordion feature to allow the Partnership to borrow up to an additional $250 million, subject to the Partnership's receipt of increased or new commitments from lenders and satisfaction of certain other conditions, and (v) reduce the applicable margin for loans by 0.25%.
The 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.” Currently, no subsidiaries have been designated as “Unrestricted Subsidiaries.” The credit facility requires us 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 June 30, 2014, TEP is in compliance with the covenants required under the revolving credit facility.
The unused portion of the credit facility is subject to a commitment fee, which was initially 0.375%, and after June 25, 2014, ranges from 0.300% to 0.500%, based on our total leverage ratio. As of June 30, 2014, the weighted average interest rate on outstanding borrowings was 1.95%.
Working Capital
Working capital is the amount by which current assets exceed current liabilities. As of June 30, 2014, we had a working capital deficit of $18.6 million compared to a working capital deficit of $37.8 million at December 31, 2013, which represents a decrease in the working capital deficit of $19.1 million.
Our working capital requirements have been, and we expect will continue to be, primarily driven by changes in accounts receivable and accounts payable. Factors impacting changes in accounts receivable and accounts payable could include the timing of collections from customers and payments to suppliers, as well as the level of spending for capital expenditures and changes in the market prices of energy commodities that we buy and sell in the normal course of business. The overall decrease in the working capital deficit from December 31, 2013 to June 30, 2014 was primarily attributable to a decrease in accounts payable of $32.3 million driven by payments of invoices related to capital projects, a decrease in related party payables of $3.2 million, an increase in inventory balances of $2.6 million, and a decrease in accrued taxes of $1.6 million, partially offset by a decrease in prepayments and other current assets of $15.2 million driven by $17.0 million of reimbursements from TD for the Replacement Gas Facilities, a decrease in net gas imbalances of $2.5 million, and a decrease in accounts receivable of $2.3 million.
A material adverse change in operations or available financing under our revolving credit facility could impact our ability to fund our requirements for liquidity and capital resources in the future.
Cash Flows
The following table and discussion presents a summary of our cash flow for the periods indicated:
 
Six Months Ended June 30,
 
2014
 
2013
 
(in thousands)
Net cash provided by (used in):
 
 
 
Operating activities
$
34,953

 
$
32,683

Investing activities
$
(179,092
)
 
$
(21,065
)
Financing activities
$
144,155

 
$
(10,343
)

35


Operating Activities. Cash flows provided by operating activities were $35.0 million and $32.7 million for the six months ended June 30, 2014 and 2013, respectively. The increase in net cash flows provided by operating activities of $2.3 million million was primarily driven by the increase in operating results and an increase in net cash inflows related to reimbursements for the Pony Express Replacement Gas Facilities of $12.5 million, partially offset by an increase in net cash outflows for changes in working capital driven by a $14.5 million decrease in net cash inflows from accounts receivable due to the settlement of related party receivable balances during the six months ended June 30, 2013 and a $7.8 million increase in net cash outflows for accounts payable and accrued liabilities primarily due to a decrease in construction payables.
Investing Activities. Cash flows used in investing activities were $179.1 million and $21.1 million for the six months ended June 30, 2014 and 2013, respectively. During the six months ended June 30, 2014, net cash used in investing activities was primarily driven by cash outflows of $150 million for the acquisition of Trailblazer and $7.6 million for the acquisition of additional equity interest in the Water Solutions business, as well as capital expenditures of $19.9 million primarily related to the Douglas expansion at TMID and expansion projects at Trailblazer and $2.0 million in cash contributions made to GWSI. In the six months ended June 30, 2013, net cash used in investing activities was driven by $20.7 million in capital expenditures consisting primarily of the capacity expansion and efficiency upgrade projects at TMID, and to a lesser extent, capital expenditures at TIGT.
Financing Activities. Cash flows provided by financing activities were $144.2 million for the six months ended June 30, 2014 compared to cash flows used in financing activities of $10.3 million for the six months ended June 30, 2013. Financing cash inflows for the six months ended June 30, 2014 consisted of the proceeds from net borrowings under the revolving credit facility of $146.0 million, a contribution from TD of $27.5 million representing the difference between the carrying amount of the Replacement Gas Facilities and the proceeds received from TD, reimbursement of stock compensation expense from TD of $2.4 million, and $0.3 million proceeds from the issuance of general partner units. These cash inflows were partially offset by distributions to TEP unitholders of $26.8 million, distributions of $2.9 million made from Trailblazer to TD prior to our acquisition of Trailblazer on April 1, 2014, and payments for deferred financing costs of $2.3 million associated with the amendment of TEP's revolving credit facility in the second quarter of 2014.
Cash flows used in financing activities were $10.3 million for the six months ended June 30, 2013 and consisted of net distributions to TD of $118.5 million in addition to the proceeds and expenses associated with the Offering and associated debt transactions as discussed below. Between November 13, 2012 and May 17, 2013, TEP Predecessor participated in a centralized cash management system with TD, and upon the completion of our IPO on May 17, 2013, TIGT and TMID entered into one with TEP. Under the cash management system, all cash balances of the TEP Predecessor were swept on a daily basis and the balances were periodically settled and recorded as equity distributions. Therefore, the TEP Predecessor did not have cash balances at the end of any period and cash flows from financing activities is equal to the total of cash flows from operating activities and cash flows from investing activities in all periods presented.
During the six months ended June 30, 2013, cash flows used in financing activities included net distributions to TD as discussed above for the period from January 1, 2013 to May 17, 2013 from TIGT and TMID to TD and for the period from January 1, 2013 to June 30, 2013 from Trailblazer to TD, in addition to proceeds net of expenses associated with the IPO and the associated debt transactions. Gross proceeds from the IPO totaled $313.9 million, and were partially offset by costs incurred in connection with the IPO of $23.2 million. In addition, cash flows used in financing activities reflect a net outflow of $181.0 million related to the associated debt transactions, including the repayment of $400.0 million of debt assumed from TD, partially offset by net borrowings under the revolving credit facility of $224.0 million and payments for deferred financing costs of $5.0 million.
Distributions
We intend to pay quarterly distributions at or above the amount of the MQD, which is $0.2875 per unit. As of August 1, 2014, we had a total of 49,769,531 common, subordinated and general partner units outstanding, which equates to an aggregate MQD of approximately $14.3 million per quarter and $57.2 million per year. We do not have a legal obligation to pay distributions except as provided in our partnership agreement. A distribution of $0.38 per unit for the three months ended June 30, 2014 was declared on July 1, 2014 and will be paid on August 14, 2014 to unitholders of record on July 30, 2014.
Capital Requirements
Our business is capital-intensive, requiring significant investment to maintain and improve existing assets. We have budgeted approximately $10.9 million for capital expenditures for the remainder of 2014 with approximately $2.6 million being related to the Gas Replacement Facilities and other costs associated with the Pony Express Abandonment, for which we will receive reimbursement from TD. The remaining approximately $8.3 million is related to maintenance and expansion capital expenditures, with the majority currently being estimated for maintenance capital expenditures.

36


Contractual Obligations
There have been no material changes in our contractual obligations as reported in our 2013 Form 10-K.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Critical Accounting Policies and Estimates
The critical accounting policies and estimates used in the preparation of our condensed consolidated financial statements are set forth in our 2013 Form 10-K for the year ended December 31, 2013 and have not changed.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
The profitability of our processing contracts that include keep whole or percent of proceeds components is affected by volatility in prevailing NGL and natural gas prices. As of June 30, 2014 approximately 87% of our reserved capacity was subject to fee-based contracts, with the remaining 13% subject to percent of proceeds or keep whole contracts, a notable recent shift toward fee-based contracts as compared to approximately 66% fee-based contracts and approximately 34% of percent of proceeds or keep whole contracts as of December 31, 2013. We do not currently hedge the commodity exposure in our processing contracts and we do not expect to in the foreseeable future. Our Processing segment comprised approximately 28% and 31% of our Adjusted EBITDA for the three and six months ended June 30, 2014.
We also have a limited amount of direct commodity price exposure related to natural gas collected related to electrical compression costs and lost and unaccounted for gas on the TIGT System. Historically, we have entered into derivative contracts with third parties for a substantial majority of the gas we expect to collect during the current year for the purpose of hedging our commodity price exposures. We expect to continue these hedging activities for the foreseeable future. As of June 30, 2014, we had natural gas swaps outstanding with a notional volume of approximately 0.6 Bcf short and 0.6 Bcf long, representing a portion of the natural gas that is expected to be sold by our Gas Transportation and Storage segment through the end of 2014. The fair value of these swaps was a liability of approximately $0.4 million at June 30, 2014.
We measure the risk of price changes in our natural gas swaps utilizing a sensitivity analysis model. The sensitivity analysis measures the potential income or loss (i.e., the change in fair value of the derivative instruments) based upon a hypothetical 10% movement in the underlying quoted market prices. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. We enter into derivative contracts solely for the purpose of mitigating the risks that accompany certain of our business activities and, therefore, both the sensitivity analysis model and the change in the market value of our outstanding derivative contracts are offset largely by changes in the value of the underlying physical natural gas sales. A hypothetical 10% increase in the natural gas price forward curve would have no aggregate impact for the quarter ended June 30, 2014 as a result of our hedging program. For the purpose of determining the change in fair value associated with the hypothetical natural gas price increase scenario, we have assumed a parallel shift in the forward curve through the end of 2014.
Our sensitivity analysis represents an estimate of the reasonably possible gains and losses that would be recognized on the natural gas derivative contracts (including fixed price swaps and basis swaps) assuming hypothetical movements in future market prices and is not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses may differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market prices, operating exposures and the timing thereof, as well as changes in the notional volumes of our outstanding derivatives during the year.
The Commodity Futures Trading Commission (“CFTC”) has promulgated regulations to implement Dodd-Frank’s changes to the Commodity Exchange Act, including the definition of commodity-based swaps subject to those regulations. The CFTC regulations are intended to implement new reporting and record keeping requirements related to those swap transactions and a mandatory clearing and exchange-execution regime for various types, categories or classes of swaps, subject to certain exemptions, including the trade-option and end-user exemptions. Although we anticipate that most, if not all, of our swap transactions should qualify for an exemption to the clearing and exchange-execution requirements, we will still be subject to record keeping and reporting requirements. Other changes to the Commodity Exchange Act made as a result of the Dodd-Frank Act and the CFTC’s implementing regulations could significantly increase the cost of entering into new swaps.

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Interest Rate Risk
As described in “Liquidity and Capital Resources Overview” above, we currently have an $850 million revolving credit facility. Borrowings under the credit facility will bear interest, at our option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar Rate, plus, in each case, an applicable margin. For loans bearing interest based on the base rate, the applicable margin was initially 1.00%, and for loans bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin was initially 2.00%. After June 25, 2014, the applicable margin ranges from 0.75% to 2.75%, based upon our total leverage ratio and whether we have elected the base rate or the reserve adjusted Eurodollar rate. We do not currently hedge the interest rate risk on our borrowings under the credit facility. However, in the future we may consider hedging the interest rate risk or may consider choosing longer Eurodollar borrowing terms in order to fix all or a portion of our borrowings for a period of time. We estimate that a 1% increase in interest rates would decrease the fair value of the debt by $0.2 million based on the debt obligations as of June 30, 2014.
Credit Risk
We are exposed to credit risk. Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We manage our exposure to credit risk associated with customers to whom we extend credit through a credit approval process which includes credit analysis, the establishment of credit limits and ongoing monitoring procedures. We may request letters of credit, cash collateral, prepayments or guarantees as forms of credit support. We have historically experienced only minimal credit losses in connection with our receivables.
A substantial majority of our revenue is produced under long-term, fee-based contracts with high-quality customers. The customer base we currently serve under these contracts generally has a strong credit profile, with the majority of our revenues derived from customers with investment grade credit ratings as of June 30, 2014.

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Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a- 15(e) or Rule 15d- 15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.
Changes in Internal Control over Financial Reporting
During the second quarter of 2014, TEP completed the conversion to a new supervisory control and data acquisition ("SCADA") system for TIGT. This system was utilized to produce financial information contained in this Quarterly Report. There have not been any other changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended June 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Assessment of Internal Control over Financial Reporting
The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules requiring every public company that files reports with the SEC to include a management report on such company’s internal control over financial reporting in its annual report. Pursuant to the recently enacted Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”), our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for up to five years or through such earlier date that we are no longer an “emerging growth company” as defined in the JOBS Act. Accordingly, our first Annual Report on Form 10-K did not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by SEC rules applicable to newly public companies. Our management will be required to provide an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2014 and, accordingly, a testing program is being executed.

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PART II – OTHER INFORMATION
Item 1. Legal Proceedings
See Note 13 – Legal and Environmental Matters to the consolidated financial statements included in Part 1—Item 1.—Financial Statements of this Quarterly Report, which is incorporated here by reference.
Item 1A. Risk Factors
Item 1A of our 2013 Form 10-K for the year ended December 31, 2014 sets forth information relating to important risks and uncertainties that could materially adversely affect our business, financial condition or operating results. Those risk factors continue to be relevant to an understanding of our business, financial condition and operating results for the quarter ended June 30, 2014. Other than as set forth below, there have been no material changes to the risk factors contained in our 2013 Form 10-K for the year ended December 31, 2013.
The potential Pony Acquisition may not be completed as anticipated, or if completed, may not be beneficial to us.
The closing of this offering is not conditioned on the consummation of the potential Pony Acquisition. The Pony Acquisition is currently under review by a conflicts committee, we have not entered into a definitive agreement and there is no assurance that the Pony Acquisition will occur on or before a certain time, or at all, or on the terms proposed by Tallgrass Development. If we were unable to consummate the Pony Acquisition, we would not realize the expected benefits of the acquisition, including the additional distributable cash flow we expect to generate from the acquired assets. Accordingly, if you decide to purchase our common units, you should be willing to do so whether or not we complete the Pony Acquisition.
If we are able to negotiate a definitive agreement and receive approval from the conflicts committee and the board of directors of our general partner, the consummation of the Pony Acquisition would involve potential risks, including, without limitation, the failure to realize expected profitability, growth or accretion; the incurrence of liabilities or other compliance costs related to environmental or regulatory matters, including potential liabilities that may be imposed without regard to fault or the legality of conduct; the incurrence of unanticipated liabilities and costs for which indemnification is unavailable or inadequate; and construction cost overruns. Additionally, we share a joint tariff with third-party pipelines delivering oil from the Bakken into Guernsey, Wyoming, and one of those pipelines is currently experiencing delays in its construction and expansion efforts, the continuance of which would further delay our ability to utilize the Pony Express Pipeline at full capacity, which in turn could negatively impact our financial performance and results of operations. If we consummate the Pony Acquisition and if these risks or other unanticipated liabilities were to materialize, any desired benefits of the Pony Acquisition may not be fully realized, if at all, and our future financial performance and results of operations could be negatively impacted. In addition, even if the Pony Acquisition was consummated, the conversion of the Pony Express Assets into an oil pipeline, the construction of the southward extension to Cushing, Oklahoma, the construction of the lateral in Northeast Colorado and the expected inservice dates of the pipeline and the lateral may be delayed, all or any one of which could negatively impact our future financial performance and results of operations.
Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs, liabilities and expenditures that could exceed our current expectations.
Substantial costs, liabilities, delays and other significant issues related to environmental laws and regulations are inherent in natural gas transportation, storage and processing operations, and as a result, we may be required to make substantial expenditures that could exceed current expectations. Our operations are subject to extensive federal, state, and local laws and regulations governing health and safety aspects of our operations, environmental protection, including the discharge of materials into the environment, and the security of chemical and industrial facilities. These laws include, but are not limited to, the following:
•
Clean Air Act, or CAA, and analogous state laws, which impose obligations related to air emissions;
•
Clean Water Act, or CWA, and analogous state laws, which regulate discharge of pollutants contained in wastewater and storm water from our facilities to state and federal waters, including wetlands;
•
Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, and analogous state laws, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal;
•
Resource Conservation or Recovery Act, or RCRA, and analogous state laws, which impose requirements for the handling and discharge of hazardous and nonhazardous solid waste from our facilities;
•
Occupational Safety and Health Act, or OSHA, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to

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inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures;
•
National Environmental Policy Act, or NEPA, which requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment and which may require the preparation of Environmental Assessments and more detailed Environmental Impact Statements that may be made available for public review and comment;
•
Migratory Bird Treaty Act, which implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds and, pursuant to which the taking, killing or possessing of migratory birds is unlawful without a permit, thereby potentially requiring the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas;
•
Endangered Species Act, or ESA, and analogous state laws, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species;
•
Gold and Bald Eagle Protection Act, or GBEPA, prohibits anyone, without a permit issued by the Secretary of the Interior, from “taking” bald eagles, including their parts, nests, or eggs. The Act defines “take” as “pursue, shoot, shoot at, poison, wound, kill, capture, trap, collect, molest or disturb.”
•
Oil Pollution Act, or OPA, and analogous laws, which imposes liability for discharges of oil into waters of the United States and requires facilities which could be reasonably expected to discharge oil into waters of the United States to maintain and implement appropriate spill contingency plans; and
•
National Historic Preservation Act, or NHPA, and analogous state laws, which is intended to preserve and protect historical and archaeological sites.
Various governmental authorities, including but not limited to the U.S. Environmental Protection Agency, or EPA, the U.S. Department of the Interior, the U.S. Department of Homeland Security, and analogous Federal, State and local agencies have the power to enforce compliance with these laws and regulations and the permits and related plans issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations, permits, plans and agreements may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, and delays in granting permits.
There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to our handling of the products we transport and store, air emissions related to our operations, historical industry operations, and waste disposal practices, and the prior use of flow meters and manometers containing mercury. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including but not limited to CERCLA, RCRA and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of materials associated with natural gas and wastes on, under, or from our properties and facilities. We are currently conducting remediation at several sites to address contamination. For 2014, we have budgeted approximately $576,000 for these ongoing environmental remediation projects. Private parties, including but not limited to the owners of properties through which our pipeline system passes and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws, regulations and permits issued thereunder, or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third-party hydrocarbon storage and processing or natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours that could result in remedial action. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance does not cover all environmental risks and costs and may not provide sufficient coverage if an environmental claim is made against us.
In March 2010, the EPA announced its National Enforcement Initiatives for 2011 to 2013, which included the addition of “Energy Extraction Activities” to its enforcement priorities list. To address its concerns regarding the pollution risks raised by new techniques for oil and gas extraction and coal mining, the EPA is developing an initiative to ensure that energy extraction activities are complying with federal environmental requirements and increasing its inspection and evaluation frequency. In June 2013, the EPA extended the current National Enforcement Initiatives, including the initiative related to Energy Extraction Activities, for 2014 through 2016. We cannot predict what the results of the current initiative or any future initiative will be, or whether federal, state or local laws or regulations will be enacted in this area. If new regulations are imposed related to oil and gas extraction, the volumes of natural gas that we transport and/or process could decline and our results of operations could be materially adversely affected.
Our business may be materially and adversely affected by changed regulations and increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits

41


or plans developed thereunder. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations, or may have to implement contingencies or conditions in order to obtain such approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to our business, financial condition, results of operations and cash flows.
We are also generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses. For example, in August 2011, the U.S. EPA and the Wyoming Department of Environmental Quality conducted an inspection of the Leak Detection and Repair (“LDAR”) Program at the Casper Plant in Wyoming. In September 2011, Tallgrass Midstream, LLC received a letter from the U.S. EPA alleging violations of the Standards of Performance of Equipment Leaks for Onshore Natural Gas Processing Plant requirements under the CAA. Tallgrass Midstream, LLC received a letter from the U.S. EPA concerning settlement of this matter in April 2013 and received an additional settlement communication from the U.S. EPA and Department of Justice in July 2014. Settlement negotiations are continuing, including attempted resolution of more recently identified LDAR issues. We are not currently able to estimate the costs that may be associated with a settlement or other resolution of this matter, which could be substantial.
We have agreed to a number of conditions in our environmental permits and associated plans, approvals and authorizations that require the implementation of environmental habitat restoration, enhancement and other mitigation measures that involve, among other things, ongoing maintenance and monitoring. Governmental authorities may require, and community groups and private persons may seek to require, additional mitigation measures in the future to further protect ecologically sensitive areas where we currently operate, and would operate if our facilities are extended or expanded, or if we construct new facilities, and we are unable to predict the effect that any such measures would have on our business, financial position, results of operations or prospects.
Further, such existing laws and regulations may be revised or new laws or regulations may be adopted or become applicable to us. In addition to potential laws and regulations restricting the emission of greenhouse gases, or GHGs, there may also be potential regulations under the New Source Performance Standards, or NSPS, and/or the Maximum Available Control Technology, or MACT, standard promulgated under the CAA that may affect us. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be materially different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects.
If third-party pipelines or other midstream facilities interconnected to our systems become partially or fully unavailable, or if the volumes we transport do not meet the quality requirements or other specifications of such pipelines or facilities, our revenues and our ability to make distributions to our unitholders could be adversely affected.
Our natural gas transportation, storage and processing facilities connect to other pipelines or facilities owned and operated by unaffiliated third parties, such as Phillips 66 and others. For example, a substantial majority of the NGLs we process are transported on the Powder River pipeline owned by Phillips 66, and therefore, any downtime on this pipeline as a result of maintenance or force majeure would adversely affect us. The continuing operation of such third party pipelines, processing plants and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from weather events or other operational hazards. In addition, if the costs to us to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurred, if any of these pipelines or other midstream facilities become unable to receive, transport or process natural gas or NGLs, or if the volumes we transport or process do not meet the quality requirements of such pipelines or facilities, our revenues, operating costs and our ability to make quarterly cash distributions to our unitholders could be adversely affected. For example, in May 2014 Phillips 66 notified us of an allegation that Tallgrass Midstream, LLC had been delivering NGLs to the Powder River NGL pipeline with methanol levels in excess of applicable tolerances. Subsequent third party lab analysis of an April 2014 composite sample from the Douglas Gas Plant confirmed that recent injections may have had excessive levels of methanol. The Douglas plant was shut in completely for five days, and operated at approximately 50% of its processing capacity for another 10 days, as a result. Tallgrass Midstream paid Phillips 66 an off-spec fee equal to $684,923 for the month of April 2014 and anticipates paying off-spec fees of approximately $200,000 and $300,000 for May 2014 and June 2014, respectively. Tallgrass is working with

42


suppliers to reduce methanol levels, but off-spec fees may continue over the next several months. Phillips 66 may also, among other things, seek payment for any other costs (including those associated with overtime, testing, and shipping), penalties or damages allegedly incurred by them in connection with their processing, use or sale of the NGLs. We have sought, and will continue to seek, recovery from our upstream suppliers that we believe have delivered off-spec product to our processing facilities, although the amount of costs and penalties we can recover from upstream suppliers is uncertain. If we are required to make additional substantial payments to Phillips 66 for costs, penalties or other damages and are unable to recover such amounts from upstream suppliers, our revenues and ability to make distributions to unitholders could be adversely affected.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information
Not applicable.

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Item 6. Exhibits
 
Exhibit No.
  
Description
10.1
  
Amendment No. 1 to Credit Agreement, dated as of June 25, 2014, by and among Tallgrass Energy Partners, LP, Barclays Bank PLC, as administrative agent, and a syndicate of lenders named therein (incorporated by reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K filed on June 30, 2014)
 
 
 
31.1*
  
Rule 13a-14(a)/15d-14(a) Certification of David G. Dehaemers, Jr.
 
 
 
31.2*
  
Rule 13a-14(a)/15d-14(a) Certification of Gary J. Brauchle.
 
 
 
32.1*
  
Section 1350 Certification of David G. Dehaemers, Jr.
 
 
 
32.2*
  
Section 1350 Certification of Gary J. Brauchle.
 
 
 
101.INS*
  
XBRL Instance Document.
 
 
 
101.SCH*
  
XBRL Taxonomy Extension Schema Document.
 
 
 
101.CAL*
  
XBRL Taxonomy Extension Calculation Linkbase Document.
 
 
 
101.DEF*
  
XBRL Taxonomy Extension Definition Linkbase Document.
 
 
 
101.LAB*
  
XBRL Taxonomy Extension Label Linkbase Document.
 
 
 
101.PRE*
  
XBRL Taxonomy Extension Presentation Linkbase Document.
*    -filed herewith

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


 
 
 
Tallgrass Energy Partners, LP
 
 
 
(registrant)
 
 
 
By:
Tallgrass MLP GP, LLC, its general partner
 
 
 
 
 
 
 
 
 
Date:
August 6, 2014
By:
/s/ Gary J. Brauchle
 
 
 
 
 
Name:
Gary J. Brauchle
 
 
 
 
 
Title:
Executive Vice President, Chief
Financial Officer and Treasurer

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