Tallgrass Energy Partners LP
Annual Report 2014

Plain-text annual report

2014 ANNUAL REPORT TALLGRASS ENERGY PARTNERS, LP • 2014 ANNUAL REPORT TALLGRASS ENERGY PARTNERS, LP (NYSE: TEP) is a publicly traded, growth-oriented limited partnership formed to own, operate, acquire and develop midstream energy assets in North America. We currently provide natural gas transportation and storage services for customers in the Rocky Mountain and Midwest regions of the United States through our Tallgrass Interstate Gas Transmission and Trailblazer Pipeline systems. We provide crude oil transportation to customers in Wyoming and the surrounding region, servicing the Bakken oil production area of North Dakota and eastern Montana through our membership interest in Tallgrass Pony Express Pipeline. We also provide services for customers in Wyoming through Tallgrass Midstream at our Casper and Douglas natural gas processing and our West Frenchie Draw natural gas treating facilities and we provide water business services to customers in Colorado and Texas through BNN Water Solutions. Our operations are strategically located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford and Bakken shale formations. TALLGRASS SYSTEM MAP Tallgrass Interstate Gas Transmission BNN Water Solutions Pipeline PXP Northeast Colorado Lateral Lease of Overthrust Pipeline Capacity Oil Storage Terminal Trailblazer Pipeline Tallgrass Midstream Pony Express Pipeline Rockies Express Pipeline 0.5 0.4 0.3 0.2 0.1 0.0 $0.485 $0.410 $0.380 $0.325 Q1 ’14 Q2 ’14 Q3 ’14 Q4 ’14 TEP DISTRIBUTIONS PER UNIT 9% TEP GROSS MARGIN PROFILE 91% 120000 100000 80000 60000 40000 20000 0 $109.9 $74.6 2013 2014 ADJUSTED EBITDA (in millions) 29% TEP INVESTMENT GRADE REVENUE 71% Commodity Exposed Margin Fee-Based Margin Other Revenue Investment Grade Revenue TALLGRASS ENERGY PARTNERS NYSE: TEP Revolver Upsized to $850mm Water Business Acquisition TMID POP Contract Conversion Initial S-3 Filing Trailblazer Acquisition Follow-on Equity Offering 33.3% PXP Acquisition Commenced At-the-Market Equity Program PXP Expansion Open Season Q1 Q1 Q2 Q3 Q4 REX E2W Open Season REX Signs E2W PAs REX Expansion Open Season REX Settles with 3 MFN Shippers Prairie State Pipeline Open Season with AGL Resources REX Seneca Lateral Expansion Open Season TALLGRASS DEVELOPMENT PAGE 1 2014TALLGRASS ENERGY PARTNERS, LP • 2014 ANNUAL REPORT One year ago, I had the privilege to write the inaugural letter in TEP’s first annual report. I am privileged to author this second letter to unitholders this year. Consider this letter as “Chapter 2” of an unfolding and growing story about a growth-oriented MLP that owns, operates, acquires and develops midstream energy assets in North America. A TRADITIONAL MIDSTREAM MLP—CHAPTER 2 At TEP, we have this saying: “Not all midstream assets are created equal.” For example, in recent years there has been a pro- liferation of assets and companies that has expanded the tradi- tional definition of midstream assets. It has expanded to such an extent today that any asset between the wellhead and the furnace, gasoline tank or plastics plant can be considered midstream. This observation is worth further analysis. Low pressure plastic pipes attached to a single natural gas well are considered midstream, as is a tanker truck that moves gasoline to your local gas station. How do they compare to a 1,700-mile, 42-inch steel pipeline that moves natural gas, gasoline or crude oil from hundreds of thousands of acres and thousands of wells to hundreds of thousands of homes and automobiles? This natural gas pipeline is in fact an asset that an affiliate of TEP partially owns and operates. The comparison is important in order to point out that TEP is, in our opinion, a tradi- tional, long-lived, fee-based, big pipe midstream company that is growth-oriented. We are not investing in any and all assets that are technically considered “midstream,” but rather those that meet our criteria of long-lived, fee-based critically necessary infrastruc- ture. We feel this sets us apart. This approach impacts the business model we have, the economic stability of that business model, and the economic return opportunity we have to help build out the big pipe infrastructure that North America needs for its future. 2014—A NEW CHAPTER—EXECUTION AND GROWING THE ASSET BASE As I write this letter at the beginning of February 2015, our units have recently closed at a new all-time high above $50.00. This represents an approximately 80% increase over the prevailing unit price at the time of last year’s letter. On February 13, 2015, TEP paid an annualized distribution of $1.94 per unit or $0.485 per quarter. This represents a 53.9% increase over the annualized distribution of a year ago. For 2014, as in 2013, TEP generated cash available for distribu- tion of more than 1.20 times our distributions (excluding the 5th distribution we paid on the newly issued common units in our July 2014 primary offering). This translates to approximately $21 million of cumulative excess distribution coverage since our IPO in May 2013. This is one strong indication that all of our business segments delivered excellent results and stable performance. A year ago we talked about TEP’s vision for the future. In 2014, or chapter two, we are proud to say we continued executing on that vision. The plan moving forward remains the same: 1) Manage our cost structure in a conservative, prudent manner; 2) Expand the services and capacities of our existing assets as needed by our customers and as demanded by the energy markets we serve; 3) Acquire additional assets in accretive “drop-down” transactions from Tallgrass Development (which we call TDEV); and 4) Pursue additional midstream energy asset acquisition opportunities. In April 2014, we acquired the Trailblazer Pipeline for approx- imately $164 million. At the time, our view was that TEP was pay- ing an approximate 9.0x multiple of projected cash flow. In fact, the 2014 post-acquisition performance of Trailblazer exceeded our expectation. Business Segments PAGE 2 NATURAL GAS TRANSPORTATION & LOGISTICS The Natural Gas Transportation & Logistics segment is engaged in ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities that provide services to on-system customers (such as third-party LDCs), industrial users and other shippers. In July 2014 we priced our first post-IPO primary offering of THE MACRO ENERGY ENVIRONMENT units, raising approximately $320 million of gross proceeds. Those proceeds, along with borrowings from our credit facility, were used in September 2014 to acquire a 33.3% interest in the Pony Express (Pony) crude oil pipeline for approximately $600 million. As Pony was just starting up, we arranged for a guaranteed minimum dis- tribution supported by TDEV of $16.7 million per quarter. Thus, our purchase price was an approximate 9.0x multiple of projected cash flow from the investment for the 12-month period following the purchase. When Pony is fully operational in the second quarter of 2015, we expect it to move over 300,000 barrels of oil approximately 700 miles each day. The oil will come from the Bakken Shale in North Dakota and Montana, as well as from basins in Wyoming and Colorado, and is transported to Cushing, Oklahoma. Depending upon the oil constituency and other operational factors, Pony is capable of moving even greater volumes. Pony allows for the safe transportation of oil to trading markets with significant liquidity that allows our customers to achieve better economics than if they were forced to sell the oil in North Dakota, Montana, Wyoming or Colorado and place it in a tanker truck or rail car for further transportation. A FUTURE ROAD MAP BASED ON PAST EXECUTION A year ago we talked about the “Excellent Stable of Assets” at TDEV from which TEP has a Right of First Offer (ROFO). Specifically, we discussed the proposal to acquire Trailblazer. Accomplished. We discussed the details of the Pony crude oil project under development and our plan to put Pony into commercial service. Accomplished. And, as previously discussed, 33.3% of Pony is now owned by TEP. Accomplished. Today, a proposal is in place for TEP to acquire an additional 33.3%. As of this date, TEP has a ROFO on the remaining 66.7% of Pony. TEP also has ROFO rights on the TDEV ownership interest and operation of its 50% interest in the Rockies Express Pipeline (REX)— REX is indeed the 1,700 mile natural gas pipeline that I spoke of earlier. It is an asset that we have worked hard on to solidify its future as an integral part of the interstate natural gas system in North America. We believe that at some point in the near future it will be an excellent addition to TEP’s stable of midstream assets. In total, these ROFO assets are expected to provide TEP an opportunity to purchase a stable of accretive assets with an estimated value between $3 to $4 billion. Recently the prices of energy commodities have been very volatile with an overall move to the down side. We recognize this may be disconcerting for investors in the energy space. Even acknowledging this environment, we believe TEP is well positioned in the midstream energy MLP arena because of these simple things: • Short-term markets can be volatile and often get it wrong; long- term markets are smoother, more predictable and get it right • TEP is a traditional “big pipe” midstream company • TEP and TDEV have assets with generally long-term contracts (most are 4 to 20-year contracts) • Energy commodity supplies are increasing in North America, and those supplies need to be transported to markets • Long-term North American energy demand is increasing—this means residential, personal, commercial, industrial and business use of oil and gas is expected to continue to grow in the future. A BRIEF LOOK BACK AND A COMMITMENT FORWARD Once again, in 2014 we asked a lot of Tallgrass employees, and once again, they delivered. I hope that each and every owner of TEP will join me in sincerely thanking the Tallgrass team for their continued outstanding effort. In addition to our employees, we again thank our supporters, our unitholder Partners, our customers and our suppliers. You all make our future possible and bright. At TEP, we renew our commitment to you, our Partners, to putting forth an outstanding effort. Effort to steward our existing business, grow that business, expand our services and most impor- tantly, effort to translate all of that into outstanding investment returns from TEP. We have finished Chapter 2, but we have only just begun a success story that will play out in many more chapters to come. Sincere regards, David G. Dehaemers, Jr. President and Chief Executive Officer CRUDE OIL TRANSPORTATION & LOGISTICS The Crude Oil Transportation & Logistics segment is engaged in ownership and construction of a FERC- regulated crude oil pipeline to serve the Bakken Shale and other nearby oil producing basins. The Pony Express Mainline was placed in service in October 2014. The Crude Oil Transportation & Logistics segment also includes the construction of the Northeast Colorado Lateral, which will interconnect with the Pony Express Mainline just east of Sterling, Colorado and is expected to be placed in service during the first half of 2015. PROCESSING & LOGISTICS The Processing & Logistics segment is engaged in owner- ship 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. PAGE 3 TALLGRASS ENERGY PARTNERS, LP • 2014 ANNUAL REPORT SUMMARY FINANCIAL INFORMATION (in thousands, except coverage and per unit data) Net income attributable to partners Add: Interest expense, net of noncontrolling interest Depreciation and amortization expense, net of noncontrolling interest Loss on extinguishment of debt Non-cash (gain) loss related to derivative instruments Non-cash compensation expense Distributions from unconsolidated investment Gain on remeasurement of unconsolidated investment Less: Non-cash loss allocated to noncontrolling interest Equity in earnings of unconsolidated investment Adjusted EBITDA Add: Pony Express preferred distributions in excess of distributable cash flow attributable to Pony Express Pony Express deficiency payments Less: Maintenance capital expenditures Cash interest cost Distributions to noncontrolling interest Cash flow attributable to predecessor operations Distributable cash flow (DCF) Less: Distributions Amounts in excess of distributions Distribution coverage Distribution coverage, excluding $3,181,000 paid in August on follow-on equity offering units TOTAL UNITHOLDER RETURN Tallgrass Energy Partners, LP 2014 2013 $ 70,681 $ 14,179 FINANCIAL AND UNIT PERFORMANCE Our focus on our customers, our markets and finan- cial discipline generated another strong year in 7,648 11,141 2014. Our units (NYSE: TEP) and the distributions on 45,389 — (184) 5,136 1,464 (9,388) (10,151) (717) 29,549 17,526 386 1,798 — — — — $ 109,878 $ 74,579 5,429 5,378 (9,913) (6,266) (5,361) (3,086) — — (8,773) (5,910)(a) — — 96,059 59,896(a) (83,329) (49,140)(a) $ 12,730 $ 10,756(a) 1.15x 1.22x(a) 1.20x our units have combined for a total return since our IPO in May of 2013 well in excess of 100% and we have outperformed our industry index as well as the broader NYSE index. We’re off to a great start but we have only just begun. (a) Ind icated amounts presented for the twelve months ended December 31, 2013 are on a pro forma basis, which assumes that our initial public offering and related formation transactions, including borrowings under our revolving credit facility, had closed on January 1, 2013. No cash distributions were paid with respect to the first quarter of 2013, and a prorated distribution of available cash was paid for the period from the closing of the IPO (May 17, 2013) through the end of the second quarter. Pro forma distribu- tions were calculated using the minimum quarterly distribution for the first two quarters of 2013 and the increased distribution for the third and fourth quarters. Actual cash distributions for the twelve- month period ending December 31, 2013, were $0.7547/unit. Pro forma interest expense (inclusive of commitment fees) for the twelve months ended December 31, 2013 was calculated by multi- plying the actual cash interest cost for Q3 by three and adding the actual cash interest cost for Q4. Actual cash interest cost for the twelve-month period ended December 31, 2013, was $3,555,000. Management believes the pro forma presentation of distributable cash flow, distribution coverage and net income per limited part- ner unit provides investors with useful information to compare our historical financial results to future periods. These pro forma financial measures are presented for illustrative purposes only and are not necessarily indicative of the operating results or the finan- cial position that would have been achieved had the initial public offering and related formation transactions been consummated on January 1, 2013 or of the results that may be obtained in the future. 5/13/13 6/28/13 9/30/13 12/31/13 3/31/14 6/30/14 9/30/14 12/31/14 Tallgrass Energy Partners, LP (TEP) NYSE Composite Index Total Return (NYATR) Alerian Total Return MLP Index (AMZX) $250 225 200 175 150 125 100 75 PAGE 4 250 225 200 175 150 125 100 75 FORM 10-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K (Mark One) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended December 31, 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 (State or other Jurisdiction of Incorporation or Organization) 46-1972941 (IRS Employer Identification Number) 4200 W. 115th Street, Suite 350 Leawood, Kansas (Address of Principal Executive Offices) 66211 (Zip Code) (913) 928-6060 (Registrant's Telephone Number, Including Area Code) Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered Common Units Representing Limited Partner Interests New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes No Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer", "accelerated filer", and "smaller reporting company" in Rule 12b-2 of the Exchange Act. Large accelerated filer Accelerated filer (Check one): Non-accelerated filer (Do not check if a smaller reporting company) Smaller reporting company Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No The aggregate market value of voting and non-voting common equity held by non-affiliates on June 30, 2014, the last business day of the Registrant’s most recently completed second fiscal quarter (based on the closing sale price of $38.80 of the Registrant’s Common Units, as reported by the New York Stock Exchange on such date) was approximately $546.1 million. On February 19, 2015, the Registrant had 49,034,105 Common Units and 834,391 General Partner Units outstanding. TALLGRASS ENERGY PARTNERS, LP TABLE OF CONTENTS PART I Item 1. Business Item 1A. Risk Factors Item 1B. Unresolved Staff Comments Item 2. Properties Item 3. Legal Proceedings Item 4. Mine Safety Disclosures PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Item 6. Selected Financial Data Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Item 7A. Quantitative and Qualitative Disclosures About Market Risk Item 8. Financial Statements and Supplementary Data CONSOLIDATED BALANCE SHEETS CONSOLIDATED STATEMENTS OF INCOME (LOSS) CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL CONSOLIDATED STATEMENTS OF CASH FLOWS NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosures Item 9A. Controls and Procedures Item 9B. Other Information Part III Item 10. Directors, Executive Officers and Corporate Governance Item 11. Executive Compensation Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Item 13. Certain Relationships and Related Transactions, and Director Independence Item 14. Principal Accounting Fees and Services Part IV Item 15. Exhibits, Financial Statement Schedules SIGNATURES 1 2 14 48 48 48 48 49 49 51 52 76 78 80 81 82 83 84 85 122 122 122 123 123 128 131 132 135 137 137 139 Bakken oil production area: Montana and North Dakota in the United States and Saskatchewan and Manitoba in Canada. Glossary of Common Industry and Measurement Terms Barrel (or bbl): Forty two U.S. gallons. Base Gas (or Cushion Gas): The volume of gas that is intended as permanent inventory in a storage reservoir to maintain adequate pressure and deliverability rates. BBtu: One billion British Thermal Units. Bcf: One billion cubic feet. British Thermal Units or Btus: the amount of heat energy needed to raise the temperature of one pound of water by one degree Fahrenheit. Condensate: A NGL with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions. Contract barrels: Barrels of crude oil that our customers have contractually agreed to ship in exchange for assurance of capacity and deliverability to delivery points. Delivery point: the point at which product in a pipeline is delivered to the end user. Dry gas: A gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing. Dth: A dekatherm, which is a unit of energy equal to 10 therms or one million British thermal units. End-user markets: The ultimate users and consumers of transported energy products. Fee Based Processing Contracts: Natural gas processing contracts that are primarily based upon a fixed fee and/or a volumetric-based fee rate, which is typically tied to reserved capacity or inlet volumes. FERC: Federal Energy Regulatory Commission. Firm transportation and storage services: Those services pursuant to which customers receive firm assurances regarding the availability of capacity and deliverability of natural gas on our assets up to a contracted amount at specified receipt and delivery points. Firm transportation contracts obligate our customers to pay a fixed monthly reservation charge to reserve an agreed upon amount of pipeline capacity for transportation regardless of the actual pipeline capacity used by the customer during each month. Firm storage contracts obligate our customers to pay a fixed monthly charge for the firm right to inject, withdraw and store a specified volume of natural gas regardless of the amount of storage capacity actually utilized by the customer. Fractionation: The process by which NGLs are further separated into individual, more valuable components including ethane, propane, butane, isobutane and natural gasoline. GAAP: Generally accepted accounting principles in the United States of America. GHGs: Greenhouse gases. Header system: Networks of medium-to-large-diameter high pressure pipelines that connect local gathering systems to large diameter high pressure long-haul transportation pipelines. HP: Horsepower. Interruptible transportation and storage services: Those services pursuant to which customers receive only limited assurances regarding the availability of capacity and deliverability in transportation or storage facilities, as applicable, and pay fees based on their actual utilization of such assets. Under interruptible service contracts, our customers pay fees based on their actual utilization of assets for transportation and storage services. These customers are not assured capacity or service. Keep Whole Processing Contracts: Natural gas processing contracts in which we are required to replace the Btu content of the NGLs extracted from inlet wet gas processed with purchased dry natural gas. Line fill: The volume of oil, in barrels, in the pipeline from the origin to the destination. Liquefied natural gas or LNG: Natural gas that has been cooled to minus 161 degrees Celsius for transportation, typically by ship. The cooling process reduces the volume of natural gas by 600 times. Local distribution company or LDC: LDCs are involved in the delivery of natural gas to consumers within a specific geographic area. MMBtu: One million British Thermal Units. Mcf: One thousand cubic feet. MMcf: One million cubic feet. Natural gas liquids or NGLs: Those hydrocarbons in natural gas that are separated from the natural gas as liquids through the process of absorption, condensation, adsorption or other methods in natural gas processing or cycling plants. Generally such liquids consist of propane and heavier hydrocarbons and are commonly referred to as lease condensate, natural gasoline and liquefied petroleum gases. Natural gas liquids include natural gas plant liquids (primarily ethane, propane, butane and isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities). Natural Gas Processing: The separation of natural gas into pipeline-quality natural gas and a mixed NGL stream. Non-contract barrels: Barrels of crude oil that our customers ship based solely on availability of capacity and deliverability with no assurance of future capacity. No-notice service: Those services pursuant to which customers receive the right to transport or store natural gas on assets outside of the daily nomination cycle without incurring penalties. NYMEX: New York Mercantile Exchange. Park and loan services: Those services pursuant to which customers receive the right to store natural gas in (park), or borrow gas from (loan), our facilities on a seasonal basis. Percent of Proceeds Processing Contracts: Natural gas processing contracts in which we process our customer’s natural gas, sell the resulting NGLs and residue gas and divide the proceeds of those sales between us and the customer. Some percent of proceeds contracts may also require our customers to pay a monthly reservation fee for processing capacity. PHMSA: The United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration. Play: A proven geological formation that contains commercial amounts of hydrocarbons. Receipt point: The point where production is received by or into a gathering system or transportation pipeline. Reservoir: A porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is characterized by a single natural pressure system. Residue gas: The natural gas remaining after being processed or treated. Shale gas: Natural gas produced from organic (black) shale formations. Tailgate: The point at which processed natural gas and NGLs leave a processing facility for end-user markets. TBtu: One trillion British Thermal Units. Tcf: One trillion cubic feet. Throughput: The volume of natural gas or crude oil transported or passing through a pipeline, plant, terminal or other facility during a particular period. Uncommitted Shippers (also known as "Walk-Up Shippers"): Customers of our Pony Express System that have not signed long-term shipper contracts and have rights under the FERC tariff as to rates and capacity allocation that are different than long-term committed shippers. Wellhead: The equipment at the surface of a well that is used to control the well’s pressure; also, the point at which the hydrocarbons and water exit the ground. Working gas: The volume of gas in the storage reservoir that is in addition to the cushion or base gas. It may or may not be completely withdrawn during any particular withdrawal season. Conditions permitting, the total working capacity could be used more than once during any season. Working gas storage capacity: The maximum volume of natural gas that can be cost-effectively injected into a storage facility and extracted during the normal operation of the storage facility. Effective working gas storage capacity excludes base gas and non-cycling working gas. X/d: The applicable measurement metric per day. For example, MMcf/d means one million cubic feet per day. PART I As used in this Annual 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 term our "general partner" refers to Tallgrass MLP GP, LLC. References to "Tallgrass Development" or "TD" refer to Tallgrass Development, LP. References to "Kelso" are to Kelso & Company and its affiliated investment funds and, as the context may require, other entities under its control, and references to "EMG" are to The Energy & Minerals Group, its affiliated investment funds and, as the context may require, other entities under its control. A reference to a "Note" herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8. —Financial Statements and Supplementary Data. 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 Annual 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 Annual Report include our expectations of plans, strategies, objectives, growth and anticipated financial and operational performance, including guidance regarding our and TD’s infrastructure programs, revenue projections, capital expenditures and tax position. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Annual Report. Actual results may vary materially. You are cautioned not to place undue reliance on any forward- looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include: • • • • • • • • • • • • • • • our ability to complete and integrate acquisitions from Tallgrass Development or from third parties, including our acquisitions of the Trailblazer Pipeline and of a 33.3% interest in Tallgrass Pony Express Pipeline, LLC ("Pony Express") that were completed in 2014 and our potential acquisition of an additional 33.3% interest in Pony Express offered to us by Tallgrass Development, which is subject to review, negotiations and approval by the conflicts committee and by the board of directors of our general partner; changes in general economic conditions; competitive conditions in our industry; actions taken by third-party operators, processors and transporters; the demand for natural gas transportation, storage and processing services and crude oil transportation services; our ability to successfully implement our business plan; our ability to complete internal growth projects on time and on budget; the price and availability of debt and equity financing; the availability and price of natural gas and crude oil, and fuels derived from both, to the consumer compared to the price of alternative and competing fuels; competition from the same and alternative energy sources; energy efficiency and technology trends; operating hazards and other risks incidental to transporting crude oil and transporting, storing and processing natural gas; natural disasters, weather-related delays, casualty losses and other matters beyond our control; interest rates; labor relations; 1 • • • • • 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 Annual 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. Item 1. Business Overview We are a publicly traded, growth-oriented Delaware limited partnership formed in 2013 to own, operate, acquire and develop midstream energy assets in North America. We currently provide natural gas transportation and storage services for customers in the Rocky Mountain and Midwest regions of the United States through our Tallgrass Interstate Gas Transmission system, which we refer to as the TIGT System, and the Trailblazer Pipeline. We provide crude oil transportation to customers in Wyoming and the surrounding region, servicing the Bakken oil production area of North Dakota and eastern Montana through our membership interest in Pony Express, which owns the Pony Express crude oil pipeline system, which we refer to as the Pony Express System. We also provide services for customers in Wyoming through Tallgrass Midstream at our Casper and Douglas natural gas processing and our West Frenchie Draw natural gas treating facilities, which we refer to collectively as the Midstream Facilities, and we provide water business services to customers in Colorado and Texas through BNN Water Solutions, LLC, which we refer to as Water Solutions. Our operations are strategically located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton- Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford and Bakken shale formations. We intend to continue to leverage our relationship with TD and utilize the significant experience of our management team to execute our growth strategy of acquiring midstream assets from TD and third parties, increasing utilization of our existing assets and expanding our systems through construction of additional assets. Our reportable business segments are: • Natural Gas Transportation & Logistics—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities; • Crude Oil Transportation & Logistics—the ownership and operation of a crude oil pipeline system; and • Processing & Logistics—the ownership and operation of natural gas processing, treating and fractionation facilities, as well as water business services provided primarily to the oil and gas exploration and production industry. Additional segment and financial information is contained in our segment results included in Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations and the notes to our consolidated financial statements included in Item 8.—Financial Statements and Supplementary Data of this Annual Report. 2 Our Assets Our assets currently consist of the TIGT System, the Trailblazer Pipeline, the Pony Express System, the Midstream Facilities, and Water Solutions, each of which is described in more detail below. The following map shows the TIGT System, the Trailblazer Pipeline, the Midstream Facilities, the Pony Express System and Water Solutions' fresh water pipeline located in Weld County, Colorado. Natural Gas Transportation & Logistics Segment TIGT System. The TIGT System is a FERC-regulated natural gas transportation and storage system with approximately 4,653 miles of varying diameter transportation pipelines serving Wyoming, Colorado, Kansas, Missouri and Nebraska. The natural gas currently transported on the TIGT System primarily comes from the Denver-Julesburg Basin and the Niobrara and Mississippi Lime shale formations. The TIGT System also includes the Huntsman natural gas storage facility located in Cheyenne County, Nebraska. The TIGT System primarily provides transportation and storage services to on-system customers such as local distribution companies and industrial users, including ethanol plants, and irrigation and grain drying operations, which depend on the TIGT System’s interconnections to their facilities to meet their demand for natural gas and a majority of whom pay FERC-approved recourse rates. For the year ended December 31, 2014, approximately 87% of the TIGT System's transportation revenue was generated from contracts with on-system customers. Trailblazer Pipeline. The Trailblazer Pipeline is a FERC-regulated natural gas pipeline system with approximately 436- miles of transportation pipelines that begins along the border of Wyoming and Colorado and extends to Beatrice, Nebraska with a total system design capacity of approximately 902 MMcf/d, substantially all of which is subscribed for under firm transportation contracts. 3 The following tables provide information regarding our Natural Gas Transportation & Logistics segment assets as of December 31, 2014 and for the years ended December 31, 2014, 2013, and 2012: Approximate Number of Miles Approximate Compression (Horsepower) Approximate Average Daily Throughput (MMcf/d) Year Ended December 31, 2014 2013 2012 Transportation ..................................................... 5,089 196,958 955 991 1,074 Overall Gas Storage Capacity (Bcf) Working Gas Storage Capacity (Bcf) Maximum Withdrawal Rate (MMcf/d) Storage ................................................................................................................................. 35.1 15.1 210 Approximate Design Capacity Total Firm Contracted Capacity (1) Approximate % of Capacity Subscribed under Firm Contracts Weighted Average Remaining Firm Contract Life (2) Transportation ............................................................ 1,982 MMcf/d 1,439 MMcf/d Storage ....................................................................... 15.1 Bcf (3) 11 Bcf 73% 73% 3 years 7 years (1) Reflects total capacity reserved under long-term firm contracts (contracts with an initial duration greater than one year), including backhaul service, as of December 31, 2014. (2) Weighted by contracted capacity as of December 31, 2014. (3) Represents working gas storage capacity. Crude Oil Transportation & Logistics Segment Pony Express System. We own a 33.3% membership interest in Pony Express, which is consolidated by TEP for financial reporting purposes. Pony Express owns and operates the Pony Express System, an approximately 698-mile crude oil pipeline commencing in Guernsey, Wyoming, and terminating in Cushing, Oklahoma, with delivery points at the Ponca City Refinery and at Deeprock in Cushing. Upon completion of ongoing construction, the Pony Express System will also include an approximately 66-mile lateral in Northeast Colorado that will commence in Weld County, Colorado, and interconnect with the Pony Express System just east of Sterling, Colorado. The lateral in Northeast Colorado is expected to be in service sometime during the first half of 2015. TD owns the remaining 66.7% membership interest in Pony Express. The table below sets forth certain information regarding our Crude Oil Transportation & Logistics segment as of December 31, 2014 and for the year ended December 31, 2014: Approximate Design Capacity (bbls/d) (1) Approximate Contractible Capacity Under Contract (2) Weighted Average Remaining Firm Contract Life (3) Approximate Average Daily Throughput (bbls/d) (4) 229,500 100% 5 years 85,229 (1) In service capacity out of Guernsey, Wyoming as of December 31, 2014. The completion of the lateral on the Pony Express System located in Northeast Colorado will add approximately 90,500 bbls/d of design capacity and is expected to be completed in the second quarter of 2015. (2) We will always make no less than ten percent of design capacity available for uncommitted, or "walk-up", shippers. Approximately 100% of the remaining design capacity (or available contractible capacity) is committed under contract. (3) Based on the average annual reservation capacity for each such contract's remaining life. (4) Approximate average daily throughput for the year ended December 31, 2014 is reflective of the volumetric ramp-up due to commercial in-service of the Pony Express System beginning in October 2014 and delays in the construction and expansion efforts of third-party pipelines with which Pony Express shares joint tariffs. 4 Processing & Logistics Segment Midstream Facilities. We own and operate natural gas processing plants in Casper and Douglas, Wyoming and a natural gas treating facility at West Frenchie Draw, Wyoming. The Casper plant also has a NGL fractionator with a capacity of approximately 3,500 barrels per day. The West Frenchie Draw treating facility extracts or reduces impurities, such as carbon dioxide and sulfur, from certain volumes of our natural gas prior to delivery to our Casper or Douglas processing plants. The Casper and Douglas plants currently have combined processing capacity of approximately 190 MMcf/d. The natural gas processed and treated at these facilities primarily comes from the Wind River Basin and the Powder River Basin, both in central Wyoming. The Douglas and Casper plants straddle the TIGT System for inlet feed to provide residue gas delivery to the TIGT System. Gathering systems owned by third parties deliver gas into our processing facilities. NGLs produced by the Casper and Douglas plants are either sold into local markets consisting primarily of retail propane dealers and oil refiners or sold to Phillips 66 Company via its Powder River NGL pipeline. Currently, over 96% of our existing processing capacity at our Midstream Facilities has been reserved with a weighted average contract life of three years as of December 31, 2014. The majority of our cash flow generated in this segment is fee- based due to the conversion of certain keep whole and percent of proceeds processing contracts to fee-based processing contracts during 2013 and early 2014. As of December 31, 2014, approximately 87% of our reserved capacity was subject to fee-based processing contracts, with the remaining 13% subject to percent of proceeds or keep whole processing contracts. On our fee-based processing contracts, we typically receive one, or a combination of, a reservation fee, an acreage or gathering system dedication or, a volumetric based processing fee. The revenue of our Processing and Logistics segment largely depends on the amount of natural gas that our customers actually deliver to our Casper and Douglas plants for processing. A significant percentage of our revenue is attributable to Phillips 66 Company. For the year ended December 31, 2014, Phillips 66 Company accounted for approximately 55% of our segment revenue in the Processing & Logistics segment and 31% of our revenues on a consolidated basis. The table below sets forth certain information regarding our Processing & Logistics segment as of December 31, 2014 and for the years ended December 31, 2014, 2013, and 2012: Approximate Plant Capacity (MMcf/d) (1) Approximate Capacity Under Contract Weighted Average Remaining Contract Life (2) Approximate Average Inlet Volumes (MMcf/d) Year Ended December 31, 2014 2013 2012 190 96% 3 years 152 133 123 (1) The West Frenchie Draw natural gas treating facility treats natural gas before it flows into the Casper and Douglas plants and therefore does not result in additional inlet capacity. (2) Based on the average annual reservation capacity for each such contract's remaining life. Water Solutions. We also provide water business services through our approximate 80% membership interest in Water Solutions. Water Solutions owns and operates a fresh water transportation pipeline located in Weld County, Colorado that transports water primarily for use in the exploration, development, and production of oil and natural gas. It also sources treated wastewater from municipalities in Texas and recently commenced recycling flowback water and other water produced in association with the production of oil and gas for a customer in Colorado. Tallgrass Development TD owns 26,355,480 of our common units, representing approximately 52.8% of our outstanding equity at February 19, 2015, after giving effect to the conversion on February 17, 2015 of the 16,200,000 subordinated units held by TD in accordance with the terms of our partnership agreement. TD is controlled by its general partner, Tallgrass Development GP, LLC, which is wholly-owned by Tallgrass GP Holdings, LLC ("Tallgrass GP Holdings"), the sole owner of our general partner. TD contributed the TIGT and TMID assets to us in connection with our initial public offering on May 17, 2013 (the "IPO") and we acquired a 100% membership interest in the owner of the Trailblazer Pipeline, Trailblazer Pipeline Company LLC, which we refer to as Trailblazer, and a 33.3% membership interest in the Pony Express System from TD in 2014. TD continues to own and manage a substantial portfolio of midstream assets, including the following: • a 66.7% membership interest in Tallgrass Pony Express Pipeline, LLC, see "Pony Express System" above. • Tallgrass Terminals, LLC, or Terminals, which holds a 20% membership interest in Deeprock Development, LLC (the owner of a crude oil terminal in Cushing, Oklahoma with approximately 2.3 million bbls of storage capacity), and is currently constructing a crude oil terminal in Sterling, Colorado with approximately 1.3 million bbls of storage capacity; and 5 • a 50% interest in, and operation of, the Rockies Express Pipeline, or REX Pipeline, an approximately 1,712-mile natural gas pipeline with a long-haul design capacity of up to 1.8 Bcf/d, that extends from Opal, Wyoming and Meeker, Colorado to Clarington, Ohio. Pursuant to an Omnibus Agreement entered into upon the closing of the IPO, among us, our general partner, TD and its general partner (the "Omnibus Agreement"), TD granted us a right of first offer to acquire certain assets held by TD at the time of the IPO, which we refer to as the Retained Assets, if TD decides to sell such assets. The Retained Assets include TD's interest in Rockies Express Pipeline, LLC and TD's remaining interest in Tallgrass Pony Express Pipeline, LLC. Terminals is not a Retained Asset. TD is otherwise under no obligation to offer to sell us additional assets or to pursue acquisitions jointly with us, and we are under no obligation to buy any assets from TD or pursue any such joint acquisitions. However, given the significant economic interest in us held by TD and its affiliates, we believe TD will be incentivized to offer us the opportunity to acquire the Retained Assets as each continues maturing into an operating profile conducive to our principal business objective of increasing the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business. In January 2015, TD offered us the right to purchase an additional 33.3% interest in Pony Express. No definitive transaction agreement has been executed at this time and the proposed transaction remains subject to review, negotiations and approval by the conflicts committee and by the board of directors of our general partner. Competition Our principal competitors in our natural gas transportation and storage market include companies that own major natural gas pipelines, such as Wyoming Interstate Company, LLC, Colorado Interstate Gas Company, LLC, Cheyenne Plains Gas Pipeline Company, LLC and Southern Star Central Gas Pipeline, Inc., many of whom also have existing storage facilities connected to their transportation systems that compete with our storage facilities. In addition to this competition, which is primarily comprised of other pipeline companies that transport gas out of the Rocky Mountain Region, Trailblazer also delivers gas into a very competitive marketplace that receives gas from the developing shale plays like the Bakken, Marcellus and Utica. As these supplies increase, it reduces the need for traditional Rockies gas production that is accessible to Trailblazer. Pony Express encounters competition in the crude oil transportation business. A number of pipeline companies directly compete with Pony Express to service takeaway volumes in markets that Pony Express currently serves, including pipelines owned and operated by Spectra Energy, Plains All American, Suncor and SemGroup. Pony Express also competes with rail facilities, which can provide more delivery optionality to crude oil producers and marketers looking to capitalize on basis differentials between two primary crude oil price benchmarks (West Texas Intermediate Crude and Brent Crude), and with refineries that source barrels in areas served by Pony Express. We also experience competition in the natural gas processing business. Our principal competitors for processing business include other facilities that service our supply areas, such as the other regional processing and treating facilities in the Greater Powder River Basin which include plants owned and operated by Kinder Morgan, Inc., which we refer to as Kinder Morgan, ONEOK Partners, LP, Western Gas Partners, LP, Williams Partners L.P. and Meritage Midstream Services II, LLC. In addition, due to the growing nature of the liquids-rich plays in the Wind River Basin and Powder River Basin, it is possible that one of our competitors could build additional processing facilities that service our supply areas. Additionally, pending and future construction projects, if and when brought online, may also compete with our natural gas transportation, storage and processing services and our crude oil transportation services. These current and future competitors may have capital and other resources greater than ours. In addition, as a provider of midstream services to the natural gas and crude oil industries, we generally compete with other forms of energy available to consumers, including electricity, coal, propane and fuel oils. Several factors influence the demand for natural gas and crude oil, including price changes, the availability of natural gas and crude oil and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, weather, and the ability to convert to alternative fuels. Regulatory Environment Federal Energy Regulatory Commission We provide open-access interstate transportation service on our natural gas transportation systems pursuant to tariffs approved by the FERC. As interstate transportation and storage systems, the rates, terms of service and continued operations of the TIGT System and the Trailblazer Pipeline are subject to regulation by the FERC, under among other statutes, the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or the NGPA, and the Energy Policy Act of 2005, or EP Act 2005. The rates and terms of service on the Pony Express System are subject to regulation by the FERC under the Interstate Commerce Act, or the ICA, and the Energy Policy Act of 1992. We provide interstate transportation service on the Pony Express System pursuant to tariffs on file with the FERC. 6 The FERC’s authority over crude oil pipelines is less broad than its authority over interstate natural gas pipelines and extends to rates, operating terms and conditions of service, the form of tariffs governing service, the maintenance of accounts and records, relationships among affiliated transporters and shippers, and depreciation and amortization policies. The FERC has jurisdiction over, among other things, the construction, ownership and commercial operation of pipelines and related facilities used in the transportation and storage of natural gas in interstate commerce, including the modification, extension, enlargement and abandonment of such facilities. The FERC also has jurisdiction over the rates, charges and terms and conditions of service for the transportation and storage of natural gas in interstate commerce. The rates and terms for access to natural gas pipeline transportation services are subject to extensive regulation and the FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of these initiatives, interstate natural gas transportation and marketing entities have been substantially restructured to remove barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from competing effectively with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The FERC’s regulations require, among other things, that interstate natural gas pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas market participants, provide internet access to current information about available pipeline capacity and other relevant information, and permit pipeline shippers under certain circumstances to release contracted transportation and storage capacity to other shippers, thereby creating secondary markets for such services. The result of the FERC’s initiatives has been to eliminate interstate natural gas pipelines’ historical role of providing bundled sales service of natural gas and to require pipelines to offer unbundled storage and transportation services on a nondiscriminatory basis. The rates for such transportation and storage services are subject to the FERC’s ratemaking authority, and the FERC exercises its authority by applying cost-of-service principles to limit the maximum and minimum levels of tariff-based recourse rates; however it also allows for the negotiation of rates as a cost-based alternative rate and may grant market-based rates in certain circumstances, typically with respect to storage services. The FERC regulations also restrict interstate natural gas pipelines from sharing transportation or customer information with marketing affiliates and require that the transmission function personnel of interstate natural gas pipelines operate independently of the marketing function personnel of the pipeline or its affiliates. 2014 Trailblazer Rate Settlement Trailblazer initiated a rate proceeding with the FERC on July 1, 2013 to implement a general rate increase to its recourse rates, initiate a rolled-in rate structure for expansion facilities certificated in 2001, and adopt miscellaneous other updates to its General Terms and Conditions in its tariff. On February 24, 2014, Trailblazer submitted to the FERC an uncontested offer of settlement and stipulation to resolve the proceeding by, among other things: (a) setting new maximum recourse rates based upon a "black box" cost of service of $21.1 million, (b) revising the charges and methods for recovery of fuel costs (natural gas and electric power used in providing service), (c) providing for revenue sharing of certain interruptible and short-term firm service revenues with eligible maximum recourse rate firm service shippers, (d) establishing a rate moratorium until January 1, 2016, and (e) requiring a general rate case to be filed no later than January 1, 2019. The FERC accepted the settlement agreement by letter order on May 29, 2014. Per the terms of the settlement, Trailblazer is required to file a new general rate case by January 1, 2019, and no settling party may file to change the settlement rates before January 1, 2016. 2011 TIGT Section 5 Fuel Settlement In 2011, the FERC approved a settlement reducing TIGT’s rates for fuel and lost and unaccounted for gas prospectively. Our current fuel rates reflect the settlement rates. As part of the settlement, TIGT is required to file with the FERC a cost and revenue study prior to November 1, 2015, although TIGT has no obligation to file an NGA Section 4 rate proceeding. Pony Express Abandonment On August 6, 2012, TIGT filed an application with the FERC to: (1) abandon approximately 433 miles of mainline natural gas pipeline facilities, along with associated rights of way and other related equipment (collectively, the "Pony Express Assets"), and the natural gas service therefrom, and transfer those assets to Pony Express (which has since converted those assets into the Pony Express System); and (2) construct and operate certain replacement-type facilities necessary to continue service to existing natural gas firm transportation customers following the conversion, which we refer to as the Replacement Gas Facilities. The FERC approved TIGT's application on September 12, 2013. 7 In December 2013, TIGT removed the Pony Express Assets from gas service and sold those assets to Pony Express for approximately $83.0 million. In this Annual Report, we refer to (i) the abandonment of the Pony Express Assets, (ii) the construction of the Replacement Gas Facilities and incremental costs of continuing existing gas service at TIGT and related contractual reimbursements, (iii) the sale of the Pony Express Assets to Pony Express and (iv) ongoing reimbursements from Pony Express to TIGT for costs incurred to construct the Replacement Gas Facilities and to transport gas on third party pipelines to enable continuation of service to customers who previously received gas transported on the abandoned portion of the TIGT System, collectively as the "Pony Express Abandonment." For additional information, see Note 16 – Regulatory Matters to the Consolidated Financial Statements in Item 8.—Financial Statements and Supplementary Data. Initiation of Service on the Pony Express System The construction of the Pony Express System consists of three primary phases: (1) conversion of 433 miles of the Pony Express Assets from a natural gas pipeline into a crude oil pipeline, (2) construction of an approximately 266-mile extension from the converted pipeline to Cushing, Oklahoma, and (3) construction of an approximate 66-mile expansion lateral in northeast Colorado. The first two parts of the project are complete. Following line fill, the Pony Express System was placed in service in October 2014. The third part of the project is scheduled to be placed in service during the first half of 2015. Following completion of the lateral in northeast Colorado, the total system design capacity of the Pony Express System will be approximately 320,000 bbls/d. Of that, approximately 287,450 bbls/d, equal to 90% of the pipeline capacity, is committed to shippers under 5 year firm contracts. The remaining 10%, equal to approximately 32,550 bbls/d, of the system design capacity is allocated for walk-up (or uncommitted) shippers. In anticipation of placing the Pony Express System into service, several petitions for declaratory orders were submitted to the FERC by Tallgrass Pony Express Pipeline LLC, its predecessor Kinder Morgan Pony Express Pipeline, LLC, and certain upstream pipelines interconnected with Pony Express to address considerations related to the Pony Express pipeline system and other matters. In response to these petitions, the FERC issued three declaratory orders (two in 2012 and one in 2014) approving the proposed rate structures and terms of service for Pony Express. Pony Express also submitted public tariff filings to the FERC to adopt a tariff with initial terms and conditions of service, as well as initial contract and non-contract rates. The effective date of these filings was October 1, 2014 for initial terms and conditions and non-contract rates and November 1, 2014 for initial contract rates. Compliance with 2014 FERC Show Cause Order Issued to All Interstate Pipelines Regarding Notice of Offers to Purchase Released Capacity On March 20, 2014, the FERC issued an Order to Show Cause to all interstate natural gas pipelines requiring the pipelines to revise their respective FERC Gas Tariffs to provide for the posting of offers to purchase released capacity as required by 18 C.F.R. §284.8(d). Both TIGT and Trailblazer submitted compliance filings proposing revisions to their respective tariffs, and the FERC accepted their compliance filings to be effective October 21, 2014. Market Behavior Rules; Posting and Reporting Requirements The Energy Policy Act of 2005, or the EPAct 2005, among other matters, amended the NGA to add an anti-manipulation provision that makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by the FERC and, furthermore, provides the FERC with additional civil penalty authority. The FERC adopted rules implementing the anti-manipulation provision of the EPAct 2005 that make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas transportation services subject to the jurisdiction of the FERC to (1) use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. These anti-manipulation rules apply to interstate gas pipelines and storage companies and intrastate gas pipelines and storage companies that provide interstate services as well as otherwise non-jurisdictional entities to the extent the activities are conducted ‘‘in connection with" gas sales, purchases or transportation subject to FERC jurisdiction. These anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but only to the extent such transactions do not have a ‘‘nexus’’ to jurisdictional transactions. The EPAct 2005 also amended the NGA and the NGPA to give the FERC authority to impose civil penalties for violations of these statutes, up to $1 million per day per violation. In connection with this enhanced civil penalty authority, the FERC issued policy statements on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. Should we fail to comply with all applicable FERC-administered statutes, rule, regulations and orders, we could be subject to substantial penalties and fines. 8 The EPAct of 2005 also amended the NGA to authorize the FERC to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce. The FERC has taken steps to enhance its market oversight and monitoring of the natural gas industry by adopting rules that (1) require buyers and sellers of annual quantities of 2,200,000 MMBtu or more of gas in any year to report by May on the aggregate volumes of natural gas they purchased or sold at wholesale in the prior calendar year; (2) report whether they provide prices to any index publishers and, if so, whether their reporting complies with the FERC’s policy statement on price reporting; and (3) increase the Internet posting obligations of interstate pipelines. In addition, the Commodity Futures Trading Commission, or CFTC, is directed under the Commodities Exchange Act, or CEA, to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act, or Dodd-Frank Act, in July 2010 and other authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1 million or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA. Further, the Federal Trade Commission ("FTC") has the authority under the Federal Trade Commission Act ("FTCA") and the Energy Independence and Security Act of 2007 ("EISA") to regulate wholesale petroleum markets. The FTC has adopted anti-market manipulation rules, including prohibiting fraud and deceit in connection with the purchase or sale of certain petroleum products, and prohibiting omissions of material information which distort or are likely to distort market conditions for such products. In addition to other enforcement powers it has under the FTCA, the FTC can sue violators under EISA and request that a court impose fines of up to $1 million per violation per day. FERC also has the authority under the Interstate Commerce Act ("ICA") to regulate the interstate transportation of petroleum on common carrier pipelines, including whether a pipeline’s rates or rules and regulations for service are "just and reasonable." Among other enforcement powers, FERC can order prospective rate changes, suspend the effectiveness of rates, and order reparations for damages. Pipeline and Hazardous Materials Safety Administration We are also subject to safety regulations imposed by PHMSA, including those regulations requiring us to develop and maintain integrity management programs to comprehensively evaluate certain areas along our pipelines and take additional measures to protect pipeline segments located in areas, which are referred to as high consequence areas, where a leak or rupture could potentially do the most harm. The ultimate costs of compliance with the integrity management rules are difficult to predict. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipe determined to be located in high consequence areas, or HCAs, can have a significant impact on the costs to perform integrity testing and repairs. We are currently performing inspections on certain segments of the Trailblazer Pipeline that collectively total approximately 70-miles as part of our integrity management program to identify potential areas for replacement and repair. In connection with our acquisition of the Trailblazer Pipeline, Tallgrass Development agreed to contractually indemnify us for any out of pocket costs we incur between April 1, 2014 and April 1, 2017 related to repairing or remediating the Trailblazer Pipeline, to the extent that such actions are necessitated by external corrosion caused by the pipeline’s disbonded Hi-Melt CTE coating. The contractual indemnity provided to us by Tallgrass Development is capped at $20 million and is subject to our first paying an annual $1.5 million deductible. We may not be able to recover any or all of such out of pocket costs that are not covered by this contractual indemnity from our customers unless and until we receive FERC approval to recover such costs through a general rate increase or other FERC-approved recovery mechanism. We will continue pipeline integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by the U.S. Department of Transportation regulations. The results of these tests could cause us to incur material and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipeline systems. In addition, we may be subject to enforcement actions and penalties for failure to comply with pipeline regulations. For example, on August 29, 2012, PHMSA notified TIGT that a report from an audit conducted in 2010 indicated a probable violation for failing to perform a periodic review of personnel responses to certain abnormal operations. Specifically, PHMSA cited the operation of a relief valve on March 3, 2010. TIGT responded to the notice of probable violation and requested a hearing in a response filed with PHMSA on October 1, 2012. A hearing was held on January 15, 2013 and a Final Order was received on October 30, 2013 that required us to modify our operating procedures to further address Abnormal Operating Conditions. The President signed into law in January 2012 The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or The Pipeline Safety Act of 2011, which increased penalties for violations of safety laws and rules, among other matters, and may result in the imposition of more stringent regulations in the next few years. PHMSA is also currently considering changes to its regulations. PHMSA issued an Advisory Bulletin in May 2012, which advised pipeline operators of anticipated changes in annual reporting requirements and that if they are relying on design, construction, inspection, testing, or other data to determine 9 the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing (including hydrotesting) or modifying or replacing facilities to meet the demands of such pressures, could significantly increase our costs. TIGT continues to investigate and, when necessary, report to PHMSA the miles of pipeline for which it has incomplete records for maximum allowable operating pressure ("MAOP"). We are currently undertaking an extensive internal record review in view of the anticipated PHMSA annual reporting requirements. Additionally, failure to locate such records or verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity on our pipeline. There can be no assurance as to the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Regulations, changes to regulations or an increase in public expectations for pipeline safety may require additional reporting, the replacement of some of our pipeline segments, the addition of monitoring equipment and more frequent inspection or testing of our pipeline facilities. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Pipeline Integrity and Releases From time to time, our pipelines may experience integrity issues. These integrity issues may cause explosions, fire, damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. For example, failures occurred on two separate pipeline segments of the TIGT System during 2013; one in Kimball County, Nebraska on May 4, 2013 and one in Goshen County, Wyoming on June 13, 2013. The failures both 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, we communicated to PHMSA that our investigation of the pipeline involved in the Kimball County failure is complete. We have since placed this line into oil service and restored pressure to the maximum allowable operating pressure. We are currently working with PHMSA to develop a plan to close the Corrective Action Order received from PHMSA regarding the Goshen County failure and is evaluating the cost of anticipated remediation activities. On August 31, 2014 a leak occurred at the Sterling Pump Station on the Pony Express System in Logan County, Colorado, which resulted in a release of approximately 200 bbls of crude oil. The spill was entirely contained on Tallgrass property. We have presented our incident investigation findings to PHMSA and are currently working with PHMSA on the matter. On October 7, 2014 an overpressure event occurred upstream of the Lincoln Pump Station, which resulted in an overflow of the sump at the Lincoln Pump Station. On October 28, 2014, an overpressure situation occurred at the Cushing Terminal in Payne County, Oklahoma. On November 17, 2014 a leak occurred at the Sterling Pig Adapter on the Pony Express System in Logan County, Colorado due to a one inch valve that was inadvertently left in a partial open state. This incident resulted in a spill of approximately 119 bbls of crude oil. We have presented our incident investigation findings to PHMSA and are currently working with PHMSA on the matter. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties and we may also be subject to private civil liability for such matters. For additional information, see Note 17 – Legal and Environmental Matters to our Consolidated Financial Statements in Item 8.—Financial Statements and Supplementary Data in this Form 10-K. Environmental, Health and Safety Matters The ownership, operation and expansion of our assets are subject to federal, state and local laws, regulations and potential liabilities arising under or relating to the protection or preservation of the environment, natural resources and human health. Moreover, we are subject to federal and state laws and regulations, the purpose of which is to maintain the safety of workers and the integrity of our pipelines, both generally and according to the standards applicable to the pipeline industry. The cost of complying with these laws and regulations can be significant, and we expect to incur significant compliance costs in the future as new, more stringent requirements are adopted and implemented. For example, regulation of greenhouse gas emissions under the Clean Air Act, or the CAA, and its implementing regulations could particularly result in significant cost additions. In addition, permitting requirements arising under these laws and regulations can negatively affect our ability to complete on a timely or cost-effective basis any future projects, for example, pipeline extensions, capacity expansion at processing facilities, and construction of storage facilities. We have an internal program of inspection designed to monitor and enforce compliance with pollution control and pipeline safety requirements. Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with various environmental registrations, licenses, permits, authorizations and other approvals, or submit to inspections or investigations. Liability under such laws and regulations may be incurred without regard to fault, including, for example, under the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, Resource Conservation and Recovery Act, or RCRA, and analogous state laws that establish liability for contaminated areas. We are currently conducting remediation at several sites to address contamination. For 2014, we spent approximately $270,000 and, for 2015, have budgeted approximately $691,000 for these ongoing environmental remediation projects. Private parties, including but not limited to the owners of properties through which our pipelines pass, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with such 10 laws, regulations and permits issued thereunder or for personal injury or property damage. Our insurance may not cover all environmental risks and costs and may not provide sufficient coverage in the event that an environmental claim is made against us. Failure to comply with these laws, regulations, permits, approvals or authorizations or to meet the requirements of new environmental laws, regulations or permits, approvals and authorizations, may also expose us to civil, criminal and administrative fines, penalties and/or temporary or permanent interruptions in our operations that could influence our business, financial position, results of operations and prospects. For example, if an accidental leak or release of crude oil, natural gas or other hazardous substance occurs from our pipelines, we may experience significant operational disruptions and we may also have to pay a significant amount in costs to clean up the leak or release, pay for government penalties, address natural resource damages, provide compensation for human exposure or property damage, comply with issued injunctions, which could compel us to take steps such as installing costly pollution control equipment or limiting or ceasing some or all of our operations, or a combination of these and other measures. The costs and liabilities resulting from a failure to comply with environmental laws and regulations could negatively affect our business, financial position, results of operations and prospects. In addition, emission controls required under the CAA and other similar federal, state and local laws could require significant capital expenditures at our facilities. In addition, we have agreed to a number of conditions in our environmental permits, 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 in the future, and we are unable to predict the effect that any such measures would have on our business, financial position, results of operations or prospects. We are also subject to the requirements of the Occupational Health and Safety Act, or OSHA, the Pipeline Safety Improvement Act and other comparable federal and state statutes. In general, we expect that we may have to increase expenditures in the future to comply with higher industry and regulatory safety standards. Such increases in expenditures could become significant over time. For additional information regarding Environmental, Health and Safety Matters, please read Item 1A.—Risk Factors. Developments in GHG Regulations Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas and products produced from crude oil, are examples of greenhouse gasses, or GHGs. The United States Environmental Protection Agency, or the EPA, has determined that the emission of GHGs present an endangerment to public health and the environment because emissions of such gases contribute to the warming of the Earth’s atmosphere and other climatic changes. Various laws and regulations exist or are under development that seek to regulate the emission of such GHGs, including EPA programs to control GHG emissions and state actions to develop statewide or regional programs. In recent years, the U.S. Congress has considered, but not adopted, legislation to reduce emissions of GHGs. Because our operations, including our compressor stations, emit various types of GHGs, primarily methane and carbon dioxide, such new legislation or regulation could increase our costs related to operating and maintaining our facilities. Depending on the particular new law, regulation or program adopted, we could be required to incur capital expenditures for installing new emission controls on our facilities, acquire permits or other authorizations for emissions of GHGs from our facilities, acquire and surrender allowances for our GHG emissions, pay taxes related to our GHG emissions and administer and manage a GHG emissions program. We are not able at this time to estimate such increased costs; however, as is the case with similarly situated entities in the industry, they could be significant to us. While we may be able to include some or all of such increased costs in the rates charged by our pipelines, such recovery of costs in all cases is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final legislation or other regulations. Similarly, while we may be able to recover some or all of such increased costs in the rates charged by our processing facilities, such recovery of costs is uncertain and may depend on the terms of our contracts with our customers. Any of the foregoing could have an adverse effect on our business, financial position, results of operations and prospects. EPA Regulation of Internal Combustion Engines Internal combustion engines used in our operations are also subject to EPA regulation under the CAA. The EPA published new regulations on emissions of hazardous air pollutants from reciprocating internal combustion engines on August 20, 2010. On January 14, 2013, the EPA signed a final rule amending these regulations that was published in the Federal Register on January 30, 2013. The EPA also revised the New Source Performance Standards, or NSPS, for stationary compression ignition and spark ignition internal combustion engines on June 28, 2011 and made minor amendments, included in the January 14, 2013 final rule. Compliance with these new regulations may require significant capital expenditures for physical modifications 11 and may require operational changes as well. We anticipate modest future cost increases for compliance with these rules, as activities such as routine major engine overhauls or facility permitting changes could subject existing engines to rule requirements which were not previously applicable. Regulation of Hydraulic Fracturing A portion of our customers’ crude oil and natural gas production is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into shale formations to stimulate crude oil and/or gas production. The practice of hydraulic fracturing has been subject to public scrutiny in recent years and various efforts to regulate, or in some cases prohibit, hydraulic fracturing have been, and are still being, pursued at the local, state and federal levels of government. For example, several states, including states in which we operate, have imposed disclosure requirements on hydraulic fracturing. Restrictions on hydraulic fracturing could adversely affect our operations by reducing the volumes of crude oil and natural gas that we transport and in other ways. EPA Rules Regarding Oil and Natural Gas Air Emissions On April 17, 2012, the EPA approved final rules that establish new air emission controls for oil and natural gas production, pipelines and processing operations. These rules were published in the Federal Register on August 16, 2012 and became effective on October 15, 2012. They have since been modified by EPA and are currently subject to ongoing legal challenge. Compliance with such rules could result in additional costs, including increased capital expenditures and operating costs. While we are not able at this time to estimate such additional costs, as is the case with similarly situated entities in the industry, they could be significant for us. Compliance with such rules may also make it more difficult for our customers to operate, thereby reducing the volume of crude oil and/or natural gas transported through our pipelines, which may adversely affect our business. Hazardous Substances and Waste Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, nonhazardous and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of nonhazardous and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, CERCLA and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release or threatened release of a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or analogous state laws, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released or threatened to be released into the environment. We also generate wastes that are subject to RCRA and comparable state laws. RCRA regulates both nonhazardous and hazardous solid wastes, but it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. It is possible that wastes resulting from our operations that are currently treated as non-hazardous wastes could be designated as "hazardous wastes" in the future, subjecting us to more rigorous and costly management and disposal requirements. It is also possible that federal or state regulatory agencies will adopt stricter management or disposal standards for non-hazardous wastes, including natural gas wastes. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses or otherwise impose limits or restrictions on our operations or those of our customers. We currently own or lease properties where hydrocarbons are being or have been handled for many years. Hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the locations where these hydrocarbons and wastes have been transported for treatment or disposal. We could also have liability for releases or disposal on properties owned or leased by others. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners and operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. Water The federal Clean Water Act, or CWA, the Oil Pollution Act of 1990, or OPA, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including petroleum products, into state waters as well as waters of the United States and impose requirements affecting our ability to conduct construction activities in waters and wetlands. The term “waters of the United States” is already broadly construed, and the EPA and the U.S. Army Corps of Engineers recently proposed a rule to clarify the term “waters of the United States.” While the proposed rule is ambiguous, many interested parties believe that the proposed rule will expand federal jurisdiction under the Clean Water Act, if it is made final in its current form. Certain state regulations and general permits issued under the federal National Pollutant Discharge Elimination System 12 program prohibit the discharge of pollutants and chemicals. Unauthorized discharges can subject owners of regulated facilities to strict, joint, and potentially unlimited liability for containment and removal costs, natural resource damages and other consequences. Spill prevention, control and countermeasure requirements of federal laws and analogous state laws require us to maintain spill prevention control and countermeasure plans. These laws also require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. Regulations promulgated pursuant to OPA further require certain facilities to maintain oil spill prevention and oil spill contingency plans. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of stormwater runoff and wastewater from certain types of facilities. These permits may require us to monitor and sample the stormwater runoff and wastewater from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater. Our water business services are also subject to unique regulation at the state and federal levels. As an example of state-level regulation, the Colorado Oil and Gas Conservation Commission regulates the reuse and recycling of water associated with oil and gas operations. Additionally, the Texas Commission on Environmental Quality regulates the production, provision, and use of reclaimed water. As discussed further in Item 1A.—Risk Factors, the EPA, in addition to other federal agencies, is considering regulation of hydraulic fracturing. Any federal regulation of water used in, or produced in association with, hydraulic fracturing could directly affect our water business services, as well as reducing demand for our other services. State regulation of water supply could also affect our water business services, particularly in Texas, which has experienced drought conditions for many years. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for noncompliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. Endangered Species The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unlisted endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans or limit future development in the affected areas. National Environmental Policy Act The National Environmental Policy Act, or NEPA, establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA and, as a result, many activities requiring FERC or other federal approval must undergo a NEPA review. A NEPA review can create delays and increased costs that could materially adversely affect our operations. Employee Safety We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances. Seasonality Weather generally impacts natural gas demand for power generation and heating purposes, which in turn influences the value of transportation and storage. Price volatility also affects gas prices, which in turn influences drilling and production. Peak demand for natural gas typically occurs during the winter months, caused by heating demand. We do not expect our crude oil transportation segment to encounter market based seasonality. Nevertheless, because a high percentage of our natural gas transportation and storage and crude oil transportation revenues are derived from firm capacity reservation fees under long- term, firm contracts, our revenues attributable to those segments are not generally seasonal in nature. We experience some seasonality in our processing segment, as volumes at our processing facilities are slightly higher in the summer months. We also experience some seasonality in our maintenance, repair, overhaul, integrity, and other projects, as warm weather months are most conducive to efficient execution of these activities. Title to Properties and Rights-of-Way Our real property falls into two categories: (i) parcels that we own in fee and (ii) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our pipelines and facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our pipelines and facilities are 13 located are held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessors. We have leased or owned much of these lands for many years without any challenge relating to the title to the land upon which our assets are located that resulted in any material adverse impact to our operations, and we believe that we have satisfactory leasehold estates or fee ownership to such lands in all material respects. We believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses, and we have no knowledge of any challenge that we expect will impact our title to such assets or their underlying fee title in any material respect. Some of the leases, easements, rights-of-way, permits and licenses we acquire, including those we acquired in the IPO, require the consent of the grantor of such rights, which in certain instances is a governmental entity. The transferor, such as TD or its affiliates, may continue to hold record title to portions of certain assets until we make the appropriate filings in the jurisdictions in which such assets are located and obtain any consents and approvals that are not obtained prior to transfer. Such consents and approvals would include those required by federal and state agencies or political subdivisions. In some cases, TD may, where required consents or approvals have not been obtained, temporarily hold record title to property as nominee for our benefit and in other cases may, on the basis of expense and difficulty associated with the conveyance of title, cause its affiliates to retain title, as nominee for our benefit, until a future date. We anticipate that there will be no material change in the tax treatment of our common units resulting from TD holding the title to any part of such assets subject to future conveyance or as our nominee. Insurance We generally share insurance coverage with TD, for which we reimburse TD and its affiliates pursuant to the terms of the Omnibus Agreement. The TD insurance program includes general and excess liability insurance, auto liability insurance, workers’ compensation insurance and property insurance. We maintain, through our general partner, director and officer liability insurance under a separate policy from TD’s general partner, for which we reimburse our general partner pursuant to our partnership agreement. All insurance coverage is in amounts which management believes are reasonable and appropriate. Employees We do not have any employees. We are managed and operated by the board of directors and executive officers of our general partner. All of our employees are employed by an affiliate of the general partner of TD and devote the portion of their time to our business and affairs that is reasonably required to manage and conduct our operations. Under the terms of the Omnibus Agreement and our partnership agreement, we reimburse TD and our general partner, respectively, for the provision of various general and administrative services for our benefit and for direct expenses incurred by TD or our general partner on our behalf, including services performed and expenses incurred by our executive management personnel in connection with our business and affairs. Available Information We make certain filings with the SEC, including our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports. We make such filings available free of charge through our website, www.tallgrassenergy.com, as soon as reasonably practicable after they are filed with the SEC. The filings are also available through the SEC’s website, www.sec.gov, at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. Our press releases and recent presentations are also available on our website. Item 1A. Risk Factors Limited partner interests are inherently different from shares of capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. If any of the following risks were to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay quarterly distributions on our common units at the current distribution level, or pay any distribution at all, and the trading price of our common units could decline. Risks Related to Our Business We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the quarterly distribution at the current distribution level, or at all, to holders of our common units. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the quarterly distribution at the current distribution level, at the minimum quarterly distribution level, or at all. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things: 14 • • • • • • • • • • • • • • the level of firm transportation and storage capacity sold, the volume of natural gas and crude oil we transport and the volume of natural gas we store, process, and treat; the level of production of crude oil and natural gas and the resultant market prices of natural gas, NGLs and crude oil; regional, domestic and foreign supply and perceptions of supply of natural gas and crude oil; the level of demand and perceptions of demand in our end-user markets; and actual and anticipated future prices of natural gas, crude oil and other commodities (and the volatility thereof), all of which may impact our ability to renew and replace firm transportation, storage and processing agreements; regulatory action affecting the supply of, or demand for, natural gas and crude oil, the rates we can charge on our assets, how we contract for services, our existing contracts, our operating costs or our operating flexibility; changes in the fees we charge for our services; the effect of seasonal variations in temperature on the amount of natural gas and crude oil that we transport and the amount of natural gas that we store, process and treat; the realized pricing impacts on revenues and expenses that are directly related to commodity prices; the level of competition from other midstream energy companies in our geographic markets; the creditworthiness of our customers; the level of our operating and maintenance costs; damages to pipelines, facilities, related equipment and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters or acts of terrorism; outages in our pipeline systems or at our processing facilities; the relationship between natural gas and NGL prices and resulting effect on processing margins; leaks or accidental releases of hazardous materials into the environment, whether as a result of human error or otherwise; and • prevailing economic conditions. In addition, the actual amount of cash we will have available for distribution will depend on other factors, including: • • • • • • • • • the level and timing of capital expenditures we make; the level of our general and administrative expenses, including reimbursements to our general partner and its affiliates, including TD, for services provided to us; the cost of pursuing and completing acquisitions, if any; our debt service requirements and other liabilities; fluctuations in our working capital needs; our ability to borrow funds and access capital markets; restrictions contained in our debt agreements; the amount of cash reserves established by our general partner; and other business risks affecting our cash levels. If we are not able to renew or replace expiring customer contracts at favorable rates or on a long-term basis, our financial condition, results of operation, cash flows and ability to make cash distributions to our unitholders will be adversely affected. With respect to our natural gas transportation and logistics segment, we have experienced decreases in revenues as compared to historical periods resulting from decreased renewals of long-haul firm capacity contracts with off- system customers over the last few years. If this trend continues, our ability to make cash distributions to our unitholders may be materially impacted. We transport, store and process a substantial majority of the natural gas and crude oil on our systems under long-term contracts with terms of various durations. For the year ended December 31, 2014, approximately 93% of our natural gas transportation and storage revenues were generated under firm transportation and storage contracts. As of December 31, 2014, the weighted average remaining life of our long-term (defined as more than one-year in duration) natural gas transportation contracts and natural gas storage contracts was approximately three years and seven years, respectively, the weighted average remaining life of our oil transportation contracts was approximately five years, and the weighted average remaining life of our 15 natural gas processing contracts was approximately three years. As these contracts expire, we may be unable to obtain new contracts on terms similar to those of our existing contracts, or at all. If we are unable to promptly resell capacity from expiring contracts on equivalent terms, our revenues may decrease and our ability to make cash distributions to our unitholders may be materially impaired. For example, over the past several years, a number of our natural gas transportation and storage customers have opted not to renew their contracts for service on the TIGT System. We believe those non-renewals have been caused both by increased competition from large diameter long-haul pipeline systems that are more efficient and cost effective at transporting natural gas over long distances, as well as reduced drilling activity for dry gas in the Rocky Mountain region. These former customers are generally large producers that primarily used the TIGT System to access interstate pipelines for ultimate delivery to consuming markets outside our areas of operations, as opposed to our current customer base, which is primarily comprised of on-system regional customers, such as LDCs. The non-renewal of these transportation contracts has resulted in decreases in firm contracted capacity on the TIGT System and related decreases in total revenue. For example, our average firm contracted capacity decreased from 842 MMcf/d for the year ended December 31, 2010 to 639 MMcf/d for the year ended December 31, 2014 and transportation services revenue decreased from $143.4 million to $102.0 million over the same period, primarily due to the loss of revenue from the non-renewal of transportation contracts. We also may be unable to maintain the long-term nature and economic structure of our current contract portfolio over time. Depending on prevailing market conditions at the time of a contract renewal, transportation, storage and processing customers with fee-based contracts may desire to enter into contracts under different fee arrangements, and our potential customers may be generally unwilling to enter into long-term contracts. To the extent we are unable to renew or replace our existing contracts on terms that are favorable to us or successfully manage the long-term nature and economic structure of our contract profile over time, our revenues and cash flows could decline and our ability to make distributions to our unitholders could be materially and adversely affected. In addition, if an existing customer terminates or breaches its long-term firm transportation, storage or processing contract, we may be subject to a loss of revenue if we are unable to promptly resell the capacity to another customer on substantially equivalent terms. Our ability to renew or replace our expiring contracts on terms similar to, or more attractive than, those of our existing contracts is uncertain and depends on a number of factors beyond our control, including: • • • • • the level of existing and new competition to provide transportation, storage and processing services to our markets; the macroeconomic factors affecting crude oil and natural gas gathering economics for our current and potential customers; the balance of supply and demand for natural gas and crude oil, on a short-term, seasonal and long-term basis, in the markets we serve; the extent to which the customers in our markets are willing to contract on a long-term basis; and the effects of federal, state or local laws or regulations on the contracting practices of our customers. As a result of the acquisition of an interest in Pony Express, we are engaged in crude oil transportation, which is a new line of business for us. We cannot provide assurance that our expansion into this line of business will succeed. In September 2014, we acquired a 33.3% membership interest in Pony Express, which owns the Pony Express System, an approximately 698 mile crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma, with delivery points at Ponca City Refinery and Deeprock Development in Cushing. In January 2015, Tallgrass Development offered us an additional 33.3% membership interest in Pony Express, which, if consummated after review, negotiations and approval by a conflicts committee of the board of directors of our general partner, would result in us owning a 66.7% membership interest in Pony Express. In addition, upon completion of ongoing construction, the Pony Express System will also include an approximately 66 mile lateral in northeast Colorado that will commence in Weld County, Colorado and interconnect with the Pony Express System just east of Sterling, Colorado. The construction of the lateral in Northeast Colorado and its expected in- service date may be delayed, which could negatively impact our future financial performance and results of operations. Additionally, we share joint tariffs with third-party pipelines delivering oil from the Bakken into Guernsey, Wyoming, and those pipelines are currently experiencing delays in their construction and expansion efforts, the continuance of which would further delay our ability to utilize the Pony Express System at full capacity, which in turn could negatively impact our financial performance and results of operations. The ownership and operation of a crude oil pipeline is a new line of business for us, as our operations were previously focused on the transportation, storage and processing of natural gas. Operating a crude oil pipeline system requires different operating strategies and different managerial expertise than our current operations, and a crude oil pipeline system is subject to additional or different regulations. Failure to timely and successfully develop this new line of business in conjunction with our existing operations may have a material adverse effect on our business, financial condition and results of operations. 16 Increased competition from other companies that provide natural gas transportation, storage and processing and crude oil transportation services, or from alternative fuel sources, could have a negative impact on the demand for our services, which could materially and adversely affect our financial results. Our ability to renew or replace our existing contracts at rates sufficient to maintain current revenues and current cash flows could be adversely affected by the activities of our competitors. Some of our competitors have greater financial, managerial and other resources than we do and control substantially more transportation, storage and processing capacity and/or crude oil transportation capacity than we do. In addition, some of our competitors have assets in closer proximity to natural gas and/or crude oil supplies and have available idle capacity in existing assets that would not require new capital investments for use. For example, several pipelines access many of the same basins as our natural gas pipeline systems and transport gas to customers in the Rocky Mountain and Midwest regions of the United States. Pony Express also competes with rail facilities, which can provide more delivery optionality to crude oil producers and marketers looking to capitalize on basis differentials between two primary crude oil benchmarks (West Texas Intermediate Crude and Brent Crude). In addition, numerous other crude oil pipeline projects have been announced recently that would compete directly with our Pony Express crude oil pipeline system. Our competitors may expand or construct new transportation, storage or processing systems that would create additional competition for the services we provide to our customers, or our customers may develop their own transportation, storage and processing facilities in lieu of using ours. The potential for the construction of new processing facilities in our areas of operation is particularly acute due to the nature of the processing industry and the attractive drilling profile of geographic areas served by our Midstream Facilities. Furthermore, TD and its affiliates are not limited in their ability to compete with us. If our competitors were to substantially decrease the prices at which they offer their services, we may be unable to compete effectively and our cash flows and ability to make distributions to our unitholders may be materially impaired. Further, natural gas as a fuel, and fuels derived from crude oil, compete with other forms of energy available to users, including electricity, coal and other liquid fuels. Increased demand for such forms of energy at the expense of natural gas or fuels derived from crude oil could lead to a reduction in demand for our services. All of these competitive pressures could make it more difficult for us to renew our existing long-term, firm transportation, storage and processing contracts when they expire or to attract new customers as we seek to expand our business, which could have a material adverse effect on our business, financial condition, results of operations and prospects. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas and crude oil in the markets we serve, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas or crude oil. If we are unable to make acquisitions on economically acceptable terms from Tallgrass Development or third parties, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per unit basis. Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants, including Tallgrass Development. Other than Tallgrass Development’s obligation to offer us certain assets (if Tallgrass Development decides to sell such assets) pursuant to the right of first offer under the Omnibus Agreement, we have no contractual arrangement with Tallgrass Development that would require it to provide us with an opportunity to acquire midstream assets that it may sell. Accordingly, while we believe Tallgrass Development will be incentivized pursuant to its economic relationship with us to offer us opportunities to purchase midstream assets, there can be no assurance that any such offer will be made, and there can be no assurance we will reach agreement on the terms with respect to any acquisition opportunities offered to us by Tallgrass Development. Furthermore, many factors could impair our access to future midstream assets, including a change in control of Tallgrass Development or a transfer of the IDRs by our general partner to a third party. A material decrease in divestitures of midstream energy assets from Tallgrass Development or otherwise would limit our opportunities for future acquisitions and could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders. Our future growth and ability to increase distributions will be limited if we are unable to make accretive acquisitions from Tallgrass Development or third parties because, among other reasons, (i) Tallgrass Development elects not to sell or contribute additional assets to us or to offer acquisition opportunities to us, (ii) we are unable to identify attractive third-party acquisition opportunities, (iii) we are unable to negotiate acceptable purchase contracts with Tallgrass Development or third parties, (iv) we are unable to obtain financing for these acquisitions on economically acceptable terms, (v) we are outbid by competitors or (vi) we are unable to obtain necessary governmental or third-party consents. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis. 17 Any acquisition involves potential risks, including, among other things: • mistaken assumptions about volumes, revenue and costs, including synergies and potential growth; • • • • • • an inability to maintain or secure adequate customer commitments to use the acquired systems or facilities; an inability to integrate successfully the assets or businesses we acquire; the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate; the diversion of management’s and employees’ attention from other business concerns; unforeseen difficulties operating in new geographic areas or business lines; and a decrease in liquidity and increased leverage as a result of using significant amounts of available cash or debt to finance an acquisition. If any acquisition eventually proves not to be accretive to our distributable cash flow per unit, it could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders. If we are unable to obtain needed capital or financing on satisfactory terms to fund expansions of our asset base, our ability to make quarterly cash distributions may be diminished or our financial leverage could increase. In order to expand our asset base through acquisitions or capital projects, we may need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and may be unable to maintain or raise the level of our quarterly cash distributions. We could be required to use cash from our operations or incur borrowings or sell additional common units or other limited partner interests in order to fund our expansion capital expenditures. Using cash from operations will reduce cash available for distribution to our common unitholders. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering as well as the covenants in our debt agreements, general economic conditions and contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining funds for expansion capital expenditures through equity or debt financings, the terms thereof could limit our ability to pay distributions to our common unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate. We do not currently have any commitment with our general partner or other affiliates, including Tallgrass Development, to provide any direct or indirect financial assistance to us. We are exposed to direct commodity price risk with respect to some of our processing revenues, and our exposure to direct commodity price risk may increase in the future. Our Processing & Logistics segment operates under three types of contracts, two of which directly expose our cash flows to increases and decreases in the price of natural gas and NGLs: percent of proceeds and keep whole processing contracts. As of December 31, 2014, approximately 13% of the reserved capacity in our Processing & Logistics segment was contracted under percent of proceeds or keep whole processing contracts. Percent of proceeds processing contracts generally provide upside in high commodity price environments, but result in lower margins in low commodity price environments. Under keep whole processing contracts, our revenues and our cash flows generally increase or decrease as the prices of natural gas and NGLs fluctuate. The relationship between natural gas prices and NGL prices may also affect our profitability. When natural gas prices are low relative to NGL prices, it is more profitable for us to process natural gas under keep whole arrangements. When natural gas prices are high relative to NGL prices, it is less profitable for us and our customers to process natural gas both because of the higher value of natural gas and the increased cost (principally that of natural gas as a feedstock and a fuel) of separating the mixed NGLs from the natural gas. As a result, we may experience periods in which higher natural gas prices relative to NGL prices reduce our processing margins or reduce the volume of natural gas processed at some of our plants. In addition, NGL prices have historically been related to the market price of oil and as a result any significant changes in oil prices could also indirectly impact our operations. Indirectly, reduced commodity prices impact us through reduced exploration and production activity, which results in fewer opportunities for new business to offset natural volume declines. NGL and natural gas prices are volatile and are impacted by changes in the supply and demand for NGLs and natural gas, as well as market uncertainty. In the latter half of 2014 and the beginning of 2015, natural gas prices have declined substantially and such declines may result in lower realizations on our percent of proceeds contracts. With respect to our direct commodity price exposure, we do not currently hedge the commodity exposure in our processing contracts and, as a result, our revenues, financial condition and results of operations could be adversely impacted by fluctuations in the prices of natural gas and NGLs. As a result of our 18 commodity price exposure, significant prolonged changes in natural gas and NGL prices could have a material adverse effect on our financial condition, results of operations and our ability to make cash distributions to our unitholders. 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 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 and our oil transportation facilities connect to other pipelines or facilities owned and operated by unaffiliated third parties, such as Phillips 66, Deeprock Development, LLC 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. For example, our Pony Express System connects to upstream joint tariff pipelines, including the Belle Fourche Pipeline owned by the True Companies (which also own and operate the Bridger Pipeline) and Hiland Double H Pipeline, which are responsible for delivering a substantial portion of the crude oil for transportation on the Pony Express System. Plus, nearly all of the crude oil we transport on the Pony Express System is stored in crude oil tanks located on or pumped over to downstream pipelines that interconnect through the Deeprock Development terminal facility in Cushing, Oklahoma. The continuing operation of such third- party pipelines, processing plants, crude oil terminal facilities and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable to us for any number of reasons, including 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. For example, the operations of the Bridger Pipeline’s Poplar System will be down indefinitely due to an apparent pipeline release on or about January 21, 2015. Bridger has declared a force majeure as a result of this event and has indicated that it does not have the capacity to make up volumes on other lines that directly or indirectly deliver crude oil into designated origin points on the Pony Express System or the Belle Fourche Pipeline. The largest committed shipper on the Pony Express System has also declared a Force Majeure as a result of this incident. We are currently evaluating the impact this will have on the operations of our Pony Express System, but it could result in decreased transportation throughput, increased costs and reduced revenues. 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 to store or transport crude oil, or if the volumes we transport or process do not meet the quality requirements of such pipelines or facilities, our revenues 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. 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. Although Tallgrass Midstream was reimbursed by its upstream suppliers for substantially all of the off-spec fees imposed by Phillips 66 during 2014, Phillips 66 could also attempt to 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. 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. The revenue in our Processing and Logistics Segment largely depends on the amount of natural gas that our customers actually deliver to our natural gas processing plants. As of December 31, 2014, approximately 87% of our reserved capacity at our Casper and Douglas Natural Gas Processing Plants was subject to fee-based processing contracts (the remaining 13% was subject to percent of proceeds or keep whole processing contracts). On these fee-based contracts, our revenue is largely tied to the amount of natural gas that our customers actually deliver our Casper and Douglas plants for processing. Unlike many pipeline transportation customers, our natural gas processing customers are not generally subject to "take or pay" obligations. Thus, if our natural gas processing customers do not produce natural gas and deliver that natural gas to our processing plants to be processed, revenue for our Processing and Logistics Segment will decline. If natural gas, crude oil or NGL prices decline, as has been the case over the latter half of 2014 and the first part of 2015, our customers may make less money from the production of natural gas, crude oil or NGLs than it costs them to produce it. If that happens, our customers may not continue to produce natural gas and our revenue will decline. In addition, the fees our customers pay to reserve capacity at our processing plants may not deter those customers from processing their natural gas volumes at other facilities, with whom they may have had prior arrangements or otherwise. 19 Any significant decrease in available supplies of natural gas or crude oil in our areas of operation, or redirection of existing natural gas or crude oil supplies to other markets, could adversely affect our business and operating results. If recent lower commodity prices for oil and gas are prolonged beyond our contract lives, we may experience lower throughput volumes and reduced cash flows. Our business is dependent on the continued availability of natural gas and crude oil production and reserves. Production from existing wells and natural gas and crude oil supply basins with access to our transportation, storage and processing facilities will naturally decline over time. The amount of natural gas and crude oil reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas and crude oil transported and natural gas stored and processed on our systems and cash flows associated therewith, our customers must continually obtain adequate supplies of natural gas and crude oil. However, the development of additional natural gas and crude oil reserves requires significant capital expenditures by others for exploration and development drilling and the installation of production, storage, transportation and other facilities that permit natural gas and crude oil to be produced and delivered to our transportation, storage and processing facilities. In addition, low prices for natural gas and crude oil, regulatory limitations, including environmental regulations, or the lack of available capital for these projects could have a material adverse effect on the development and production of additional reserves, as well as storage, pipeline transportation, and import and export of natural gas and crude oil supplies. A period of sustained price reductions in crude oil or refined products could lead to a decline in drilling activity, production and refining of crude oil, or import levels in these areas. For example, in response to recent declines in crude oil prices, a number of producers in our areas of operation have announced significant reductions in their capital budget and drilling plans for 2015. In addition, production may fluctuate for other reasons, including, for example, in the case of crude oil, the decisions made by the members of the Organization of the Petroleum Exporting Countries, or OPEC, regarding production controls. Furthermore, competition for natural gas and crude oil supplies to serve other markets could reduce the amount of natural gas and crude oil supply available for our customers. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas and crude oil transported on our systems and cash flows associated with our operations, our customers must compete with others to obtain adequate supplies of natural gas and crude oil. If new supplies of natural gas and crude oil are not obtained to replace the natural decline in volumes from existing supply basins, if natural gas and crude oil supplies are diverted to serve other markets, if environmental regulations restrict new natural gas and crude oil drilling or if OPEC does not agree to and maintain production controls, the overall demand for transportation, storage and processing services on our systems may decline, which could have a material adverse effect on our ability to renew or replace our current customer contracts when they expire and on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders. Our natural gas and crude oil operations are subject to extensive regulation by federal, state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could have a material adverse effect on our business, financial condition, and results of operations. We provide open-access interstate transportation service on our natural gas transportation systems pursuant to tariffs approved by the FERC. Our natural gas transportation and storage operations are regulated by the FERC, under the Natural Gas Act of 1938, or the NGA, the Natural Gas Policy Act of 1978, or the NGPA, and the Energy Policy Act of 2005, or EPAct 2005. The TIGT System and Trailblazer Pipeline each operates under a tariff approved by the FERC that establishes rates, cost recovery mechanisms and terms and conditions of service to our customers. The rates and terms of service on the Pony Express System are subject to regulation by the FERC under the Interstate Commerce Act, or the ICA, and the Energy Policy Act of 1992. We provide interstate transportation service on the Pony Express System pursuant to tariffs on file with the FERC. Generally, the FERC’s authority over natural gas facilities extends to: • • • • • • • • rates, operating terms and conditions of service; the form of tariffs governing service; the types of services we may offer to our customers; the certification and construction of new, or the expansion of existing, facilities; the acquisition, extension, disposition or abandonment of facilities; creditworthiness and credit support requirements; the maintenance of accounts and records; relationships among affiliated companies involved in certain aspects of the natural gas business; 20 • • depreciation and amortization policies; and the initiation and discontinuation of services. The FERC’s authority over crude oil pipelines is less broad, extending to: • • • • • rates, operating terms and conditions of service; the form of tariffs governing service; the maintenance of accounts and records; relationships among affiliated transporters and shippers; and depreciation and amortization policies. Interstate natural gas pipelines subject to the jurisdiction of the FERC may not charge rates or impose terms and conditions of service that, upon review by the FERC, are found to be unjust, unreasonable, unduly discriminatory, or preferential. The maximum recourse rate that we may charge for our natural gas transportation and storage services is established through the FERC’s ratemaking process. The maximum applicable recourse rate and terms and conditions for service are set forth in our FERC-approved tariff. Pursuant to the NGA, existing interstate natural gas transportation and storage rates and terms and conditions of service may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases and changes to terms and conditions of service proposed by a regulated interstate pipeline may be protested and such increases or changes can be delayed and may ultimately be rejected by the FERC. We currently hold authority from the FERC to charge and collect (i) "recourse rates" (i.e., the maximum cost-based rates an interstate natural gas pipeline may charge for its services under its tariff); (ii) "discount rates" (i.e., rates offered by the natural gas pipeline to shippers at discounts vis-à-vis the recourse rates and that fall within the cost-based maximum and minimum rate levels set forth in the natural gas pipeline’s tariff); and (iii) "negotiated rates" (i.e., rates negotiated and agreed to by the pipeline and the shipper for the contract term that may fall within or outside of the cost-based maximum and minimum rate levels set forth in the tariff, and which are individually filed with the FERC for review and acceptance). When capacity is available and offered for sale, the rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for) at which such capacity is sold are subject to regulatory approval and oversight. Regulators and customers on our natural gas pipeline systems have the right to protest or otherwise challenge the rates that we charge under a process prescribed by applicable regulations. The FERC may also initiate reviews of our rates. Customers on our natural gas pipeline systems may also dispute terms and conditions contained in our agreements, as well as the interpretation and application of our tariffs, among other things. Rates for crude oil transportation service must be filed as a tariff with the FERC and are subject to applicable FERC regulation. The filed tariff rates include contract rates entered into with shippers willing to make long term commitments to the pipeline to support new pipeline capacity and "walk-up" rates available to uncommitted non-contract shippers. Crude oil pipelines typically must reserve at least ten percent of their capacity for walk-up shippers. Crude oil pipeline tariff rates may be adjusted, positively or negatively, on an annual basis through a FERC indexing procedure. A crude oil pipeline may also file new tariff rates at any time, subject to shipper contract restrictions and FERC regulatory procedures. The filing of any indexed rate increase or other rate increase may be protested and subjected to cost-of-service review by the FERC to determine whether the proposed new rate is just and reasonable. Under the ICA, which applies to FERC-regulated liquids pipelines such as the Pony Express System, parties having standing may challenge new or existing rates and terms and conditions of service at any time. The FERC is authorized to suspend, subject to refund, the effectiveness of a protested rate for up to seven months while it determines if the protested rate is just and reasonable. Our rates may be reduced and we may be required to issue refunds as a result of settlement or by an order of the FERC following a hearing finding that a protested rate is unjust and unreasonable. If the complaint is not resolved by settlement, the FERC may conduct a hearing and order the crude oil pipeline to make reparations going back for up to two years prior to the date on which a complaint was filed if a rate is found to be unjust and unreasonable. We cannot guarantee that any new or existing rate on the Pony Express System would not be rejected or modified by the FERC, or subjected to refunds or reparations. While the FERC regulates rates and terms and conditions of service for transportation of crude oil in interstate commerce by pipeline, state agencies may also regulate facilities (including construction, acquisition, disposition, financing, and abandonment), rates, and terms and conditions of service for crude oil pipeline transportation in intrastate commerce. Any successful challenge by a regulator or shipper in any of these matters could have a material adverse effect on our business, financial condition and results of operations. The Trailblazer Pipeline, one of our interstate natural gas pipelines, uses two types of fuel to power its compressors: (1) natural gas and (2) electric power. For the natural gas compression, customers are charged a gas retainage percentage as an in- kind reimbursement for fuel. For the electric compression, customers are charged a commodity rate for the electricity used at the pipeline’s stations. The volume of gas and cost of electric power are tracked and adjusted in annual periodic rate adjustment 21 filings made pursuant to the tariff. Lost and unaccounted for gas is also tracked and adjusted in annual periodic rate adjustment filings. These costs were subject to the NGA Section 4 rate case initiated by the Trailblazer Pipeline and resolved by settlement as approved by the FERC in May 2014. On TIGT, our gas compressor fuel costs and the cost of lost and unaccounted for gas, together referred to as Fuel Retention Factors, are recovered by retaining a fixed percentage of natural gas throughput on our transportation and storage facilities. These Fuel Retention Factors were the subject of a Section 5 proceeding initiated by the FERC that we resolved with customers by a settlement approved by the FERC in September 2011. The FERC’s jurisdiction over natural gas facilities extends to the certification and construction of interstate transportation and storage facilities, including, but not limited to, acquisitions, facility maintenance, expansions, and abandonment of facilities and services. With some exceptions applicable to smaller projects, auxiliary facilities, and certain facility replacements, prior to commencing construction and/or operation of new or existing interstate natural gas transportation and storage facilities, an interstate pipeline must obtain a certificate authorizing the construction from, or file to amend its existing certificate with, the FERC. Typically, a significant expansion project requires review by a number of governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any delay or refusal by an agency to issue authorizations or permits as requested for one or more of these projects may mean that they will be constructed in a manner or with capital requirements that we did not anticipate or that we will not be able to pursue these projects. Such delay, modification or refusal could materially and negatively impact the additional revenues expected from these projects. The FERC does not regulate the construction, expansion, or abandonment of crude oil pipelines nor the initiation or discontinuation of services on those pipelines, provided that the action taken is not discriminatory or preferential among similarly situated shippers. The FERC has the authority to conduct audits of regulated entities to assess compliance with FERC regulations and policies. The FERC also conducts audits to verify that the websites of interstate natural gas pipelines accurately provide information on the operations and availability of services on the pipeline. FERC regulations also require entities providing natural gas and crude oil transportation services to comply with uniform terms and conditions for service, as set forth in publicly available tariffs or, as it concerns natural gas facilities, agreements for transportation and storage services executed between interstate pipelines and their customers. These service agreements are generally required to conform, in all material respects, with the standard form of service agreements set forth in the natural gas pipeline’s FERC-approved tariff. The pipeline and a customer may choose to enter into a non-conforming service agreement so long as this agreement is filed with, and accepted by, the FERC. In the event that the FERC finds that an agreement, in whole or part, is materially non-conforming, FERC could reject the agreement or require us to modify the agreement, or alternatively require us to modify our tariff so that the non-conforming provisions are generally available to all customers. Agreements entered into with crude oil shippers are generally not available for public review, but the rates and terms and service provided to similarly situated shippers may not be unduly discriminatory or preferential. The FERC has promulgated rules and policies covering many aspects of our natural gas pipeline business, including regulations that require us to provide firm and interruptible transportation service on an open access basis that is not unduly discriminatory or preferential, provide internet access to current information about our available pipeline capacity and other relevant transmission information, and permit pipeline shippers to release contracted transportation and storage capacity to other shippers, thereby creating secondary markets for such services. FERC regulations also prevent interstate natural gas pipelines from sharing customer information with marketing affiliates, and restrict how interstate natural gas pipelines share transportation with marketing affiliates. FERC regulations require that certain transmission function personnel of interstate natural gas pipelines function independently of personnel engaged in natural gas marketing functions. Crude oil pipelines subject to the ICA must comply with FERC regulations that require the pipeline to act as a common carrier and not engage in undue discrimination or preferential treatment with respect to shippers. FERC policies also govern how interstate natural gas pipelines respond to interconnection requests from third party facilities, including other pipelines. Generally, an interstate natural gas pipeline must grant an interconnection request upon the satisfaction of several conditions. As a consequence, an interstate natural gas pipeline faces the risk that an interconnecting third party pipeline may pose a risk of additional competition to serve a particular market. Failure to comply with applicable provisions of the NGA, NGPA, EPAct and certain other laws, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies, including without limitation, revocation of certain authorities, disgorgement of ill-gotten gains, and civil penalties of up to $1.0 million per day, per violation. Violations of the ICA, the Energy Policy Act of 1992, or regulations and orders promulgated by the FERC are also subject to administrative and criminal penalties and remedies, including forfeiture and individual liability. 22 In addition, new laws or regulations or different interpretations of existing laws or regulations applicable to our pipeline systems or midstream facilities could have a material adverse effect on our business, financial condition, results of operations and prospects. For example, the FERC may not continue to pursue its approach of pro-competitive policies as it considers matters such as interstate pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity and transportation and storage facilities. We may face challenges to our rates or terms of service in the future. Any successful challenge could materially adversely affect our future earnings and cash flows. The rates of our regulated assets are subject to review and possible adjustment by federal and state regulators, which could adversely affect our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders. Our shippers or other interested stakeholders, such as state regulatory agencies, may challenge the rates or the terms and conditions of service applicable to our natural gas or crude oil pipeline tariffs, unless they have entered into agreements not to challenge such tariffs. The FERC has authority to investigate our rates and terms and conditions of service pursuant to NGA Section 5 for natural gas pipelines and the ICA for common carrier oil pipelines. Our crude oil firm contract shippers have generally agreed not to complain or protest rates unless they are in conflict with their contracts. With regard to our natural gas pipelines, Trailblazer initiated on its own initiative under NGA Section 4 a rate proceeding with the FERC on July 1, 2013 to implement a general rate increase to its recourse rates, initiate a rolled-in rate structure for expansion facilities certificated in 2001, and adopt miscellaneous other updates to its General Terms and Conditions in its tariff. On February 24, 2014, Trailblazer submitted to the FERC an uncontested offer of settlement and stipulation to resolve the proceeding by, among other things: (a) setting new maximum recourse rates based upon a "black box" cost of service of $21.1 million, (b) revising the charges and methods for recovery of fuel (natural gas and electric power used in providing service) costs, (c) providing for revenue sharing of certain interruptible and short-term firm service revenues with eligible maximum recourse rate firm service shippers, (d) establishing a rate moratorium until January 1, 2016, and (e) requiring a general rate case to be filed no later than January 1, 2019. The FERC accepted the settlement agreement by letter order on May 29, 2014. Per the terms of the settlement, Trailblazer is required to file a new general rate case by January 1, 2019, and no customer or participant who joined the settlement (defined in the settlement as a "Settling Party") may file to change the settlement rates before January 1, 2016. TIGT is not subject to any current moratorium on complaints or protests regarding its rates or terms and conditions of service. The rates on our TIGT natural gas pipeline system were subject to a NGA Section 5 proceeding initiated by the FERC relating to TIGT's fuel retention factors, which generally are recovered by retaining a fixed percentage of natural gas throughput on TIGT's natural gas transportation and storage facilities. TIGT resolved these issues with customers by a settlement approved by the FERC in September 2011, which resulted in a 27% reduction in the Fuel Retention Factors billed to shippers effective June 1, 2011. The Section 5 Settlement also provided for a second stepped reduction, resulting in a total 30% reduction in the Fuel Retention Factors billed to shippers and effective January 1, 2012, for certain segments of the former Pony Express natural gas pipeline system. On our crude oil pipeline system, shippers may challenge new or existing rates at any time. As a result of settlement or by order of the FERC following hearing, our rates may be reduced. If a shipper files a complaint, and if the complaint is not resolved with that shipper, to the extent the FERC determines after hearing that we have collected payment on rates not previously found to be just and reasonable, we may be required to pay reparations to that shipper for up to two years prior to the date on which a complaint was filed. Regardless of the prospective just and reasonable rate, reparations may not be required below the last rates determined by the FERC to be just and reasonable. In other words, crude oil pipelines are not required to make reparations that refund revenues collected pursuant to rates previously determined to be just and reasonable. Successful challenges to rates charged on our natural gas and crude oil pipeline systems, or to the terms and conditions of service on those systems, could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders. We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties, and any material nonpayment or nonperformance by one or more of these parties could adversely affect our financial condition, cash flows, and operating results. Although we attempt to assess the creditworthiness of our customers, suppliers and contract counterparties, there can be no assurance that our assessments will be accurate or that there will not be a rapid or unanticipated deterioration in their creditworthiness, which may have an adverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. In addition, our long-term firm transportation and storage contracts obligate our customers to pay demand charges regardless of whether they transport or store natural gas or crude oil on our facilities, except for certain circumstances when we are unable to schedule the customer’s nomination for service. As a result, during the term of our long-term firm transportation and storage contracts and absent an event of force majeure, our revenues will generally depend on our customers’ financial condition and their ability to pay rather than upon the amount of natural gas or crude oil transported. Further, our contract counterparties may not perform or adhere to our existing or future contractual arrangements. Any material nonpayment or nonperformance by our contract counterparties due to inability or unwillingness to perform or 23 adhere to contractual arrangements could have an adverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. The procedures and policies we use to manage our exposure to credit risk, such as credit analysis, credit monitoring and, in some cases, requiring credit support, cannot fully eliminate counterparty credit risks. To the extent our procedures and policies prove to be inadequate, our financial and operational results may be negatively impacted. Some of our counterparties may be highly leveraged or have limited financial resources and will be subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with such parties. As seen with the recent decline in crude oil prices, prices for crude oil and natural gas are subject to large fluctuations in response to relatively minor changes in supply and demand, market uncertainty and a variety of other factors that are beyond our control. Such volatility in commodity prices might have an impact on many of our counterparties and their ability to borrow and obtain additional capital on attractive terms, which, in turn, could have a negative impact on their ability to meet their obligations to us and may also increase the magnitude of these obligations. Any material nonpayment or nonperformance by our counterparties could require us to pursue substitute counterparties for the affected operations, reduce operations or provide alternative services. There can be no assurance that any such efforts would be successful or would provide similar financial and operational results. Constructing new assets subjects us to risks of project delays, cost overruns and lower-than-anticipated volumes of natural gas or crude oil once a project is completed. Our operating cash flows from our capital projects may not be immediate or meet our expectations. One of the ways we may grow our business is by constructing additions or modifications to our existing facilities. We also may construct new facilities, either near our existing operations or in new areas. For example, in 2013 we completed an expansion of our Casper and Douglas plants to increase processing capacity and upgrade compression. Pony Express substantially completed its approximately 698-mile crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma during 2014 and is currently constructing an approximately 66 mile lateral in Northeast Colorado. Construction projects require significant amounts of capital and involve numerous regulatory, environmental, political, legal and operational uncertainties, many of which are beyond our control. These projects also involve numerous economic uncertainties, including the impact of inflation on project costs and the availability of required resources. We may be unable to complete announced construction projects, including the potential expansion of the Pony Express System announced in our public filings, on schedule, at the budgeted cost, or at all, which could have a material adverse effect on our business and results of operations. Moreover, we may not receive any material increase in operating cash flow from a project for some time. For instance, if we expand a pipeline or processing facility, the construction expenditures may occur over an extended period of time, yet we will not receive any material increases in cash flow until the project is completed and fully operational. In addition, our cash flow from a project may be delayed or may not meet our expectations. Our project specifications and expectations regarding project cost, timing, asset performance, investment returns and other matters usually rely in part on the expertise of third parties such as engineers, technical experts and construction contractors. These estimates may prove to be inaccurate because of numerous operational, technological, economic and other uncertainties. We rely in part on estimates from producers regarding the timing and volume of anticipated natural gas and crude oil production. Production estimates are subject to numerous uncertainties, all of which are beyond our control. These estimates may prove to be inaccurate, and new facilities may not attract sufficient volumes to achieve our expected cash flow and investment return. Our success depends on the supply and demand for natural gas and crude oil. The success of our business is in many ways impacted by the supply and demand for natural gas and crude oil. For example, our business can be negatively impacted by sustained downturns in supply and demand for natural gas and crude oil in the markets that we serve, including reductions in our ability to renew contracts on favorable terms and to construct new infrastructure. One of the major factors that will impact natural gas demand will be the potential growth of the demand for natural gas in the power generation market, particularly driven by the speed and level of existing coal-fired power generation that is replaced with natural gas-fired power generation. One of the major factors impacting domestic natural gas and crude oil supplies has been the significant growth in unconventional sources such as shale plays and the continued progression of hydraulic fracturing technology. The supply and demand for natural gas and crude oil, and therefore the future rate of growth of our business, will depend on these and many other factors outside of our control, including, but not limited to: • • • adverse changes in general global economic conditions; adverse changes in domestic regulations; technological advancements that may drive further increases in production and reduction in costs of developing natural gas shales; 24 • • • the price and availability of other forms of energy; prices for natural gas, crude oil and NGLs; decisions of the members of the Organization of the Petroleum Exporting Countries regarding price and production controls; • increased costs to explore for, develop, produce, gather, process and transport natural gas or to transport crude oil; • weather conditions, seasonal trends and hurricane disruptions; • • • • the nature and extent of, and changes in, governmental regulation, for example greenhouse gas legislation, taxation and hydraulic fracturing; perceptions of customers on the availability and price volatility of our services and natural gas and crude oil prices, particularly customers’ perceptions on the volatility of natural gas and crude oil prices over the long term; capacity and transportation service into, or out of, our markets; and petrochemical demand for NGLs. We are subject to numerous hazards and operational risks. Our operations are subject to all the risks and hazards typically associated with transportation, storage and processing of natural gas and the transportation of crude oil. These operating risks include, but are not limited to: • • • • • • • damage to pipelines, facilities, equipment and surrounding properties caused by hurricanes, earthquakes, tornadoes, floods, fires or other adverse weather conditions and other natural disasters and acts of terrorism; inadvertent damage from construction, vehicles, farm and utility equipment; uncontrolled releases of crude oil, natural gas and other hydrocarbons; leaks, migrations or losses of natural gas and crude oil as a result of the malfunction of equipment or facilities; outages at our processing facilities; ruptures, fires, leaks and explosions; and other hazards that could also result in personal injury and loss of life, pollution and other environmental risks, and suspension of operations. For example, failures occurred on two separate pipeline segments of the TIGT System during 2013; one in Kimball County, Nebraska on May 4, 2013 and one in Goshen County, Wyoming on June 13, 2013. The failures both 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. TEP has since placed this line into oil service and restored pressure to full maximum allowable operating pressure. TEP is currently working with PHMSA to develop a plan to close the Corrective Action Order received from PHMSA regarding the Goshen County failure and is evaluating the cost of anticipated remediation activities. We have also had four minor incidents on the Pony Express System that we reported to PHMSA during final commissioning and since the line has been placed into commercial service. On August 31, 2014 a leak occurred at the Sterling Pump Station in Logan County, Colorado, which resulted in a release of approximately 200 bbls of crude oil. The spill was entirely contained on Tallgrass property. On October 7, 2014 an overpressure event occurred upstream of the Lincoln Pump Station, which resulted in an overflow of the sump at the Lincoln Pump Station. On October 28, 2014, an overpressure situation occurred at the Cushing Terminal in Payne County, Oklahoma. On November 17, 2014, a leak occurred at the Sterling Pig Adapter in Logan County, Colorado due to a one inch valve that was inadvertently left in a partial open state. This incident resulted in a spill of approximately 119 bbls of crude oil. The Pony Express System is a newly commissioned crude oil pipeline and these integrity issues may continue for the foreseeable future. These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. The location of certain segments of our pipeline systems in or near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas could increase the level of damages resulting from these risks. Despite the precautions we take, events such as those described above could cause considerable harm to people or property, could result in loss of service available to customers, and could have a material adverse effect on our financial condition and results of operations and ability to make distributions to unitholders. In addition, maintenance, repair and remediation activities could result in service interruptions on segments of our systems or alter the operational profile of our systems. Potential impacts arising from these service interruptions or operational 25 profile changes on segments of our systems could include, among others, limitations on our ability to satisfy customer requirements, obligations to provide reservation charge credits to customers in times of constrained capacity, and solicitation of existing customers by others for potential new projects that would compete directly with existing services. We could be required by regulatory authorities to test or undertake modifications to our systems, operations or both that could result in a material adverse impact on our business, financial condition and results of operations. For example, we received a Corrective Action Order from PHMSA on June 19, 2013 directing us to take certain investigative, testing and corrective measures with regard to the segment of the TIGT pipeline that failed on June 13, 2013. Such actions, including those required by PHMSA, could materially and adversely impact our ability to meet contractual obligations and retain customers, with a resulting material adverse impact on our business and results of operations, and could also limit or prevent our ability to make quarterly cash distributions to our unitholders. Some or all of our costs arising from these operational risks may not be recoverable under insurance, contractual indemnification or increases in rates charged to our customers. Our insurance coverage may not be adequate. We are not insured or fully insured against all risks that could affect our business, including losses from environmental accidents. For example, we do not maintain business interruption insurance in the type and amount to cover all possible losses. In addition, we do not carry insurance for certain environmental exposures, including but not limited to potential environmental fines and penalties, certain business interruptions, named windstorm or hurricane exposures and, in limited circumstances, certain political risk exposures. Further, in the event there is a total or partial loss of one or more of our insured assets, any insurance proceeds that we may receive in respect thereof may be insufficient to effect a restoration of such asset to the condition that existed prior to such loss. In addition, we are either not insured or not fully insured with respect to the legal proceedings described in "Note 17 - Legal and Environmental Matters to the consolidated financial statements included in Part II-Item 8.—Financial Statements and Supplementary Data" of our annual report on Form 10-K for the year ended December 31, 2014 and may, depending upon the circumstances, need to pay self-insured retention amounts prior to having losses covered by the insurance providers. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates, and we may elect to self-insure all or a portion of our risks of loss. As a result of market conditions, premiums and deductibles for certain types of insurance policies may substantially increase, and in some instances, certain types of insurance could become unavailable or available only for reduced amounts of coverage. Any insurance coverage we do obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses. Our pipeline integrity program may impose significant costs and liabilities on us, while increased regulatory requirements relating to the integrity of our pipeline systems may require us to make additional capital and operating expenditures to comply with such requirements. We are subject to extensive laws and regulations related to pipeline integrity. There are, for example, federal requirements set by PHMSA for owners and operators of natural gas and crude oil pipelines in the areas of pipeline design, construction, and testing, the qualification of personnel and the development of operations and emergency response plans. The rules require pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines and take measures to protect pipeline segments located in what the rules refer to as High Consequence Areas, or HCAs. Our pipeline operations are subject to pipeline safety regulations administered by PHMSA. These regulations, among other things, include requirements to monitor and maintain the integrity of our pipeline systems and determine the pressures at which our pipeline systems can operate. The Pipeline Safety Act of 2011 enacted January 3, 2012, amends the Pipeline Safety Improvement Act of 2002, or the Pipeline Safety Act of 2002, in a number of significant ways, including: • • • • reauthorizing funding for federal pipeline safety programs, increasing penalties for safety violations and establishing additional safety requirements for newly constructed pipelines; requiring PHMSA to adopt appropriate regulations within two years and requiring the use of automatic or remote- controlled shutoff valves on new or rebuilt pipeline facilities; requiring operators of pipelines to verify maximum allowable operating pressure and report exceedances within five days; and requiring studies of certain safety issues that could result in the adoption of new regulatory requirements for new and existing pipelines, including changes to integrity management requirements for HCAs, and expansion of those requirements to areas outside of HCAs. 26 PHMSA published an advanced notice of proposed rule making in August 2011 to solicit comments on the need for changes to its safety regulations, including whether to revise integrity management requirements. On August 13, 2012, PHMSA published rules to update pipeline safety regulations to reflect provisions included in the Pipeline Safety Act of 2011, including increasing maximum civil penalties from $0.1 million to $0.2 million per violation per day of violation and from $1.0 million to $2.0 million as a maximum amount for a related series of violations as well as changing PHMSA’s enforcement process. The ultimate costs of compliance with the integrity management rules are difficult to predict. The majority of the costs to comply with the rules are associated with pipeline integrity testing and the repairs found to be necessary. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipe determined to be located in HCAs or expansion of integrity management requirements to areas outside of HCAs can have a significant impact on the costs to perform integrity testing and repairs. We are currently performing inspections on certain segments of the Trailblazer Pipeline that collectively total approximately 70-miles as part of our integrity management program to identify potential areas for replacement and repair. In connection with our acquisition of the Trailblazer Pipeline, Tallgrass Development agreed to contractually indemnify us for any out of pocket costs we incur between April 1, 2014 and April 1, 2017 related to repairing or remediating the Trailblazer Pipeline, to the extent that such actions are necessitated by external corrosion caused by the pipeline’s disbonded Hi-Melt CTE coating. The contractual indemnity provided to us by Tallgrass Development is capped at $20 million and is subject to our first paying an annual $1.5 million deductible. We may not be able to recover any or all of such out of pocket costs that are not covered by this contractual indemnity from our customers unless and until we receive FERC approval to recover such costs through a general rate increase or other FERC-approved recovery mechanism. We plan to continue our pipeline integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by the DOT rules. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines, which expenditures could be material. Further, additional laws, regulations and policies that may be enacted or adopted in the future or a new interpretation of existing laws and regulations could significantly increase the amount of these expenditures. For example, PHMSA issued an Advisory Bulletin in May 2012 which advised pipeline operators that they must have records to document the maximum allowable operating pressure for each section of their pipeline and that the records must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing (including hydrotesting) or modifying or replacing facilities to meet the demands of verifiable pressures, could significantly increase our costs. TIGT continues to investigate and, when necessary, report to PHMSA the miles of pipeline for which it has incomplete records for MAOP. We are currently undertaking an extensive internal record review in view of the anticipated PHMSA annual reporting requirements. Additionally, failure to locate such records or verify maximum pressures could require us to operate at reduced pressures, which would reduce available capacity on our natural gas pipeline systems. These specific requirements do not currently apply to crude oil pipelines, but forthcoming regulations implementing the Pipeline Safety Act of 2012 likely will expand the scope of regulation applicable to crude oil pipelines. There can be no assurance as to the amount or timing of future expenditures required to comply with pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial position, results of operations and prospects.In addition, we may be subject to enforcement actions and penalties for failure to comply with pipeline regulations. On August 29, 2012, PHMSA notified TIGT that a report from an audit conducted in 2010 indicated a probable violation for failing to perform a periodic review of personnel responses to certain abnormal operations. Specifically, PHMSA cited to the operation of a relief valve on March 3, 2010. TIGT responded to the notice of probable violation and requested a hearing in a response filed with PHMSA on October 1, 2012. A hearing was held on January 15, 2013 and a Final Order was received on October 30, 2013 that required us to modify our operating procedures to further address Abnormal Operating Conditions. Failures occurred on two separate pipeline segments of the TIGT System during 2013; one in Kimball County, Nebraska on May 4, 2013 and one in Goshen County, Wyoming on June 13, 2013. The failures both 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, we communicated to PHMSA that our investigation of the pipeline involved in the Kimball County failure is complete. We have since placed this line into oil service and restored pressure to full maximum allowable operating pressure. We are currently working with PHMSA to develop a plan to close the Corrective Action Order received from PHMSA regarding the Goshen County failure and is evaluating the cost of anticipated remediation activities. 27 We have also had four minor incidents on the Pony Express System that we reported to PHMSA during final commissioning and since the line has been placed into commercial service. On August 31, 2014 a leak occurred at the Sterling Pump Station in Logan County, Colorado, which resulted in a release of approximately 200 bbls of crude oil. The spill was entirely contained on Tallgrass property. On October 7, 2014 an overpressure event occurred upstream of the Lincoln Pump Station, which resulted in an overflow of the sump at the Lincoln Pump Station. On October 28, 2014, an overpressure situation occurred at the Cushing Terminal in Payne County, Oklahoma. On November 17, 2014, a leak occurred at the Sterling Pig Adapter in Logan County, Colorado due to a one-inch valve that was left in a partial open state. This incident resulted in a spill of approximately 119 bbls of crude oil. The Pony Express System is a newly commissioned crude oil pipeline and these integrity issues may continue for the foreseeable future. There can be no assurance as to the amount or timing of future expenditures required to remediate or resolve these issues, and actual future expenditures may be different from the amounts we currently anticipate. These integrity issues could have a material adverse effect on our business, financial position, results of operations and prospects. Climate change regulation at the federal, state or regional levels could result in increased operating and capital costs for us. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas and products produced from crude oil, are examples of greenhouse gases, or GHGs. The United States Environmental Protection Agency, or the EPA, has determined that the emission of GHGs present an endangerment to public health and the environment because emissions of such gases contribute to the warming of the Earth’s atmosphere and other climatic changes. Various laws and regulations exist, or are under development that seek to regulate the emission of such GHGs, including the EPA programs to control GHG emissions and state actions to develop statewide or regional programs. In recent years, the U.S. Congress has considered, but not adopted, legislation to reduce emissions of GHGs. Based on these findings, the EPA began adopting and implementing regulations to restrict the emission of GHGs under existing provisions of the federal Clean Air Act, or CAA, starting in 2011. The EPA has issued a final rule, known as the "Tailoring Rule," that defines regulatory emission thresholds at which certain new and modified stationary sources are subject to permitting and other requirements for GHG emissions under the CAA’s Prevention of Significant Deterioration, or PSD, and Title V programs. The EPA has indicated in rule makings that it may reduce the current regulatory thresholds for GHGs, making additional sources subject to PSD permitting requirements. On June 23, 2014, the United States Supreme Court ruled that portions of EPA’s GHG regulatory program violated the CAA. Specifically, the Supreme Court determined that GHGs cannot independently trigger PSD permitting requirements. However, the Court held that certain PSD permitting requirements may apply to GHG emissions if emissions of another regulated pollutant, like sulfur dioxide or particulate matter, trigger PSD permitting. Additionally, the Supreme Court ruled that the Tailoring Rule thresholds violated the CAA, while suggesting that EPA could promulgate "de minimis" thresholds for GHGs. Further proceedings are ongoing in the United States Court of Appeals for the District of Columbia. Some of our facilities emit GHGs in excess of the Tailoring Rule thresholds and have been required to obtain a Title V Permit that reflects this potential to emit GHGs. Although these existing facilities are not currently required to obtain a PSD permit containing enforceable limits on GHG emissions, any future modifications with a potential to emit GHGs above the applicable regulatory thresholds at the time of the application, and to emit a regulated non-GHG pollutant in excess of statutory thresholds as well, would require us to obtain a PSD permit containing enforceable limits on GHG emissions. We note that, as described above, the Supreme Court’s recent decision on EPA’s GHG rules creates some uncertainty regarding applicable regulatory thresholds for GHG emissions for facilities that trigger permitting requirements based on emissions of non-GHG pollutants. Additional direct regulation of GHG emissions in our industry may be implemented under other CAA programs, including the New Source Performance Standards, or NSPS, program. The EPA has already proposed to regulate GHG emissions from certain electric generating units under the NSPS program. While these proposed regulations for electric generating units would not apply to our operations, the EPA may propose to regulate additional sources under the NSPS program. For example, the EPA has proposed a rule that it calls the "Clean Power Plan" to compel state governments to reduce GHG emissions from sources within their jurisdictions. In addition, in 2009, the EPA published a final rule requiring that specified large GHG emissions sources annually report the GHG emissions for the preceding year in the United States. In 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule for petroleum and natural gas facilities, including natural gas transportation compression facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. The rule requires reporting of GHG emissions by regulated facilities to the EPA on an annual basis. Some of our facilities are required to report under this rule, and operational and/or regulatory changes could require additional facilities to comply with GHG emissions reporting requirements. 28 At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs, primarily through the planned development of emission inventories or regional greenhouse gas "cap and trade" programs. Many of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. Depending on the particular program, we could be required to purchase and surrender emission allowances and our customers may find it less attractive to produce, own, ship or have natural gas or crude oil processed or refined. Because our operations, including our compressor stations and processing facilities, emit various types of GHGs, primarily methane and carbon dioxide, new legislation or regulation could increase our costs related to operating and maintaining our facilities, and could delay future permitting. Depending on the particular new law, regulation or program adopted, we could be required to incur capital expenditures for installation of new emission controls on our compressor stations and processing facilities, acquire and surrender allowances for our GHG emissions, pay taxes related to our GHG emissions and administer and manage a GHG emissions program. We are not able at this time to estimate such increased costs; however, they could be significant. While we may be able to include some or all of such increased costs in the rates charged by our pipelines, such recovery of costs is uncertain in all cases and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final legislation or other regulations. Similarly, while we may be able to recover some or all of such increased costs in the rates charged by our processing facilities, such recovery of costs is uncertain and may depend on the terms of our contracts with our customers. Any of the foregoing could have a material adverse effect on our business, financial position, results of operations and prospects. To the extent financial markets view climate change and greenhouse gas emissions as a financial risk, this could materially and adversely impact our cost of and access to capital. Legislation or regulations that may be adopted to address climate change, or incentives to conserve energy or use alternative energy sources, could also affect the markets for our services by making natural gas and crude oil products less desirable than competing sources of energy. 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 and crude oil transportation 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: • 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 (Section 402) or fill material (Section 404) 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 and 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 inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures; • The 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; • The Migratory Bird Treaty Act, or MBTA, 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; 29 • 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; • Bald and Golden Eagle Protection Act, or BGEPA, prohibits anyone, without a permit issued by the Secretary of the Interior, from "taking" bald or golden 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;" • The 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 archeological sites. Various governmental authorities, including but not limited to the 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, process 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 oil, 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 spent approximately $270,000 and for 2015 have budgeted approximately $691,000 for these ongoing environmental remediation projects. Private parties, including but not limited to the owners of properties through which our pipelines pass 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 non- compliance 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 June 2013, the EPA extended its National Enforcement Initiatives, enforcement priorities list, including an 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 and crude oil 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 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 additional settlement communications from the U.S. EPA and Department of Justice 30 beginning 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 GHG regulations, there may also be potential regulations under the NSPS and/or the maximum available control technology standard 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. Increased regulation of hydraulic fracturing and other oil and natural gas processing operations could affect our operations and result in reductions or delays in production by our customers, which could have a material adverse impact on our revenues. A portion of our customers’ oil and natural gas production is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into shale formations to stimulate production. Hydraulic fracturing is currently exempt from federal regulation pursuant to the federal Safe Drinking Water Act, or the SDWA (except when the fracturing fluids or propping agents contain diesel fuels, and EPA released guidance on the permitting of wells that use diesel fuels during hydraulic fracturing activities in February 2014), because hydraulic fracturing is excluded from the SDWA definition of "underground injection" and therefore is not subject to permitting and federal regulatory control pursuant to SDWA. However, public concerns have been raised related to its potential environmental impact. Additional federal, state and local laws and regulations to more closely regulate hydraulic fracturing have been considered and, in some cases, adopted and implemented. For example, from time to time, legislation to further regulate hydraulic fracturing has been proposed in Congress, including repeal of the SDWA exemption for hydraulic fracturing, as well as to require disclosure for chemicals used in hydraulic fracturing. An EPA investigation requested by a committee of the House of Representatives to assess the potential environmental effects of hydraulic fracturing on drinking water and groundwater is underway, with a first progress report outlining work currently underway by the agency released on December 21, 2012 and a final draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources was expected to be available for public comment and peer review in 2014, although it has not yet been released. Reports prepared by the U.S. Department of Energy’s Shale Gas Subcommittee could also lead to further restrictions on hydraulic fracturing. In addition, EPA has announced its intention to propose regulations under the CWA regarding wastewater discharges from hydraulic fracturing and other gas production and, on May 9, 2014, EPA issued an Advance Notice of Proposed Rulemaking under Section 8 of the Toxic Substances Control Act, or the TSCA, to seek public comment on hydraulic fracturing chemical information that could be reported and disclosed under TSCA. Apart from federal legislation and EPA regulations, other federal agencies and states have proposed or adopted legislation or regulations restricting hydraulic fracturing. On May 24, 2013, the U.S. Department of Interior published a proposed rule in the Federal Register that includes disclosure requirements and other mandates for hydraulic fracturing on federal lands. Some states have already imposed disclosure requirements associated with hydraulic fracturing, including states in which we operate. Moreover, some state and local authorities have considered or imposed new laws and rules related to hydraulic fracturing, including additional permit requirements, operational restrictions, chemical disclosure obligations and temporary or permanent bans or, in municipal settings, time, place and manner restrictions, on hydraulic fracturing in certain jurisdictions or in environmentally sensitive areas. For example, Wyoming, Kansas, Colorado, North Dakota, Montana, and Oklahoma have imposed regulations regarding disclosure of information regarding chemicals in well stimulation operations. The Governor of Colorado recently announced that he would form a task force to consider additional regulation of oil and gas activities, including hydraulic fracturing. Although we do not have operations in the State of New York, the Governor of New York announced in December 2014 that hydraulic fracturing would be banned in that state. Many local governments have restricted or banned hydraulic fracturing within their jurisdictions, including some in states in which we operate. 31 State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and gas waste waters and an observed increase in minor seismic activity and tremors. When caused by human activity, such events are called induced seismicity. In a few instances, operators of injection wells in the vicinity of minor seismic events have reduced injection volumes or suspended operations, often voluntarily. A 2012 report published by the National Academy of Sciences concluded that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity. However, some state regulatory agencies have modified their regulations to account for induced seismicity. For example, the Texas Railroad Commission rules allow the Commission to modify, suspend, or terminate a permit based on a determination that the permitted activity is likely to be contributing to seismic activity. Regulatory agencies are continuing to study possible linkage between injection activity and induced seismicity. We cannot predict whether any additional federal, state or local laws or regulations will be enacted in this area and if so, what their provisions would be. If additional levels of reporting, regulation or permitting moratoria were required or imposed related to hydraulic fracturing, the volumes of crude oil and natural gas that we transport may decline and our results of operations could be materially and adversely affected. Further, additional state legislation or regulation may impact any potential expansion plans by delaying implementation or requiring additional approvals or modifications to expansion plans. In addition, the EPA approved final rules that establish new air emission controls for oil and natural gas production, pipelines and processing operations that became effective on October 15, 2012. For new or reworked hydraulically fractured gas wells, the rules require the control of emissions through flaring or reduced emission, or green, completions until January 1, 2015. As of 2015, the rule requires the use of green completions by all such wells except wildcat (exploratory) and delineation gas wells and low reservoir pressure non-wildcat and non-delineation gas wells. The rules also establish specific new requirements regarding emissions from wet seal and reciprocating compressors at production facilities, gathering systems, boosting facilities and onshore natural gas processing plants, effective October 15, 2012, and from pneumatic controllers and storage vessels at production facilities, gathering systems, boosting facilities and onshore natural gas processing plants, effective October 15, 2013. In addition, the rules revise existing requirements for volatile organic compound emissions, or VOCs, from equipment leaks at onshore natural gas processing plants by lowering the leak definition for valves from 10,000 parts per million to 500 parts per million and requiring the monitoring of connectors, pumps, pressure relief devices and open- ended lines, effective October 15, 2012. These rules may therefore require a number of modifications to our and our customers’ operations, including the installation of new equipment to control emissions. In October 2012 several challenges to EPA’s rules were filed by various parties, including environmental groups and industry associations. In a January 1, 2013 unopposed motion to hold this litigation in abeyance, EPA indicated that it may reconsider some aspects of the rule and has since reconsidered certain aspects of the rule. The case is currently in abeyance and EPA may reconsider other aspects of the rule. Depending on the outcome of such proceedings, the rules may be modified or rescinded or EPA may issue new rules, the costs of compliance with any modified or newly issued rules cannot be predicted. Additionally, EPA has signaled its intent to regulate emissions of methane and volatile organic compounds from the oil and gas sector as a measure to implement President Obama’s Climate Action Plan. EPA has released a series of white papers addressing methane reductions from the oil and gas sector. On January 14, 2015, the Obama Administration announced that EPA will propose a rule in the summer of 2015 to set standards for methane and VOC emissions from new and modified sources in the oil and gas sector, including transmission. A final rule is expected in 2016. The Administration’s announcement also stated that other federal agencies, including the Bureau of Land Management, the PHMSA, and the Department of Energy will impose new or more stringent regulations on the oil and gas sector that will have the effect of reducing methane emissions. Depending on whether rules are promulgated and the applicability and restrictions in any promulgated rule, compliance with such rules could result in additional costs, including increased capital expenditures and operating costs. While we are not able at this time to estimate such additional costs, as is the case with similarly situated entities in the industry, they could be significant for us. Compliance with such rules may also make it more difficult for our customers to operate, thereby reducing the volume of natural gas or crude oil transported through our pipelines or the volumes of natural gas we process, which may adversely affect our business. Compliance with such rules could also generally result in additional costs, including increased capital expenditures and operating costs, for us and our customers, which could have a material adverse effect on our business. Potential increased costs as a result of EPA regulation of internal combustion engines could be significant. Internal combustion engines used in our operations are also subject to EPA regulation under the CAA. The EPA published new regulations on emissions of hazardous air pollutants from reciprocating internal combustion engines on August 20, 2010. On January 14, 2013, the EPA signed a final rule amending these regulations and it was published in the Federal Register on January 30, 2013. The EPA also revised the NSPS for stationary compression ignition and spark ignition internal combustion engines on June 28, 2011 and made minor amendments, included in the January 14, 2013 final rule. Compliance with these new regulations may require significant capital expenditures for physical modifications and may require operational changes as well. We anticipate modest future cost increases for compliance with these rules, as activities such as routine major engine overhauls or facility permitting changes could subject existing engines to rule requirements which were not previously applicable. 32 We are exposed to costs associated with lost and unaccounted for volumes. A certain amount of natural gas and crude oil may be lost or unaccounted for in normal operations in connection with their transportation across a pipeline system. Under our tariffs and contractual arrangements with our customers we are entitled to retain a specified volume of natural gas and crude oil in order to compensate us for such lost and unaccounted for volumes, as well as the natural gas used to run our natural gas compressor stations, which we refer to collectively as fuel usage. Our pipeline tariffs, other than the Trailblazer Pipeline's, do not contain fuel usage true-up mechanisms. The use of fuel (natural gas, electric and lost and unaccounted for gas) trackers on the Trailblazer Pipeline, while minimizing risk over time, nevertheless leaves the Trailblazer Pipeline exposed to the possibility of under- or over-collections on an annual basis. The level of lost and unaccounted for volumes, and natural gas fuel usage, on our pipeline systems may exceed the natural gas and crude oil volumes retained from our customers as compensation for our lost and unaccounted for volumes, and fuel usage, pursuant to our tariffs and contractual agreements, and it may be necessary to purchase natural gas or crude oil in the market to make up for the difference, which exposes us to commodity price risk. Future exposure to the volatility of natural gas and crude oil prices as a result of lost and unaccounted for volume imbalances could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders. We have certain long term fixed priced natural gas and crude oil transportation contracts that cannot be adjusted even if our costs increase, and we have certain crude oil transportation contracts that contain favored nation provisions that could require rate decreases if other similarly situated shippers are paying lower rates. As a result, our costs could exceed our revenues. Approximately one-third of our contracted natural gas transportation firm capacity is provided under long-term, fixed price "negotiated rate" contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts. It is possible that costs to perform services under our "negotiated rate" contracts will exceed the negotiated rates. If this occurs, it could decrease the cash flow realized by our assets and, therefore, the cash we have available for distributions to our unitholders. Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a "negotiated rate," which is fixed between the natural gas pipeline and the shipper for the contract term and does not necessarily vary with changes in the level of cost-based "recourse rates," provided that the affected customer is willing to agree to such rates and that the FERC has approved the negotiated rate agreement. These "negotiated rate" contracts are not generally subject to adjustment for increased costs which could be caused by inflation or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue, representing the difference between "recourse rates" (if higher) and negotiated rates, under current FERC policy, may be recoverable from other shippers in certain limited circumstances. For example, the FERC may recognize this shortfall in the determination of prospective rates in a future rate case. Approximately 90% of our crude oil pipeline capacity is provided to committed shippers under long-term "Throughput and Deficiency Agreements" or "TDAs". Rates under the TDAs are typically subject to increase only through the FERC annual index process. We generally cannot file for rate increases outside of the annual FERC adjustment process with respect to committed shippers who have signed TDAs. Some of the TDAs also contain favored nations provisions which could result in lower rates being charged to certain committed shippers to ensure that the rates such shippers are paying are no greater than ninety to one hundred percent of the rates being charged to other similarly situated shippers for similar service at similar volumes and terms. Any significant and prolonged change in or stabilization of natural gas prices could have a negative impact on our natural gas storage business. Historically, natural gas prices have been seasonal and volatile, which has enhanced demand for our storage services. The natural gas storage business has benefited from significant price fluctuations resulting from seasonal price sensitivity, which impacts the level of demand for our services and the rates we are able to charge for such services. On a system-wide basis, natural gas is typically injected into storage between April and October when natural gas prices are generally lower and withdrawn during the winter months of November through March when natural gas prices are typically higher. However, the market for natural gas may not continue to experience volatility and seasonal price sensitivity in the future at the levels previously seen. If volatility and seasonality in the natural gas industry decrease, because of increased production capacity or otherwise, then demand for our storage services and the prices that we will be able to charge for those services may decline. In addition to volatility and seasonality, an extended period of high natural gas prices would increase the cost of acquiring base gas and likely place upward pressure on the costs of associated storage expansion activities. Alternatively, an extended period of low natural gas prices could adversely impact storage values for some period of time until market conditions adjust. These commodity price impacts could have a negative impact on our business, financial condition, results of operations and ability to make distributions. 33 Certain portions of our transportation, storage and processing facilities have been in service for several decades. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our facilities that could have a material adverse effect on our business and results of operations. Significant portions of our transportation, storage and processing systems have been in service for several decades. The age and condition of our facilities could result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our facilities could adversely affect our business and results of operations and our ability to make cash distributions to our unitholders. Restrictions in our revolving credit facility could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders. Our revolving credit facility limits our ability to, among other things: • • incur or guarantee additional debt; redeem or repurchase units or make distributions under certain circumstances; • make certain investments and acquisitions; • • incur certain liens or permit them to exist; enter into certain types of transactions with affiliates; • merge or consolidate with another company; and • transfer, sell or otherwise dispose of assets. Our revolving credit facility also contains covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests. The provisions of our revolving credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our revolving credit facility, including a failure to meet the required financial ratios and tests, could result in a default or an event of default that could enable our lenders to restrict or prohibit our ability to make quarterly distributions and declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. Our future debt levels may limit our flexibility to obtain financing and to pursue other business opportunities. Our level of debt could have important consequences to us, including the following: • • our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms; our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt; • we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and • our flexibility in responding to changing business and economic conditions may be limited. Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all. 34 Increases in interest rates could adversely impact demand for our storage capacity, our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels. There is a financing cost for our customers to store natural gas in our storage facilities. That financing cost is impacted by the cost of capital or interest rate incurred by the customer in addition to the commodity cost of the natural gas in inventory. Absent other factors, a higher financing cost adversely impacts the economics of storing natural gas for future sale. As a result, a significant increase in interest rates could adversely affect the demand for our storage capacity independent of other market factors. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield- oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels. Difficult conditions in the global capital markets, the credit markets and the economy in general could negatively affect our business and results of operations. Our business may be negatively impacted by adverse economic conditions or future disruptions in the global financial markets. Included among these potential negative impacts are reduced energy demand and lower prices for our services and increased difficulty in collecting amounts owed to us by our customers which could reduce our access to credit markets, raise the cost of such access or require us to provide additional collateral to our counterparties. Our ability to access available capacity under our revolving credit facility could be impaired if one or more of our lenders fails to honor its contractual obligation to lend to us. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures. The amount of cash we have available for distribution to unitholders depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income. The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes. The lack of diversification of our assets and geographic locations could adversely affect our ability to make distributions to our common unitholders. We rely primarily on revenues generated from transportation, storage and processing systems that we own, which are primarily located in the Rocky Mountain and Midwest regions of the United States. Due to our lack of diversification in assets and geographic location, an adverse development in these businesses or our areas of operations, including adverse developments due to catastrophic events, weather, regulatory action and decreases in demand for crude oil or natural gas, could have a significantly greater impact on our results of operations and cash available for distribution to our common unitholders than if we maintained more diverse assets and locations. We do not own most of the land on which our natural gas and crude oil pipeline systems and Midstream Facilities are located, which could disrupt our operations and subject us to increased costs. We do not own most of the land on which our pipeline systems and Midstream Facilities have been constructed, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way, if such rights-of-way lapse or terminate or if our facilities are not properly located within the boundaries of such rights-of-way. For example, the West Frenchie Draw treating facility is located on land leased from the Wyoming Board of Land Commissioners pursuant to a contract that can be terminated at any time. Although many of these rights are perpetual in nature, we occasionally obtain the right to construct and operate pipelines on other owners’ land for a specific period of time. If we were to be unsuccessful in renegotiating rights-of-way, we might incur increased costs to maintain our pipeline systems, which could have a material adverse effect on our business, results of operations, financial condition and ability to make distributions to our unitholders. In addition, we are subject to the possibility of increased costs under our rental agreements with landowners, primarily through rental increases and renewals of expired agreements. Some rights-of-way for our pipeline systems and other real property assets are shared with other pipeline systems and other assets owned by third parties. We or owners of the other pipeline systems may not have commenced or concluded eminent domain proceedings for some rights-of-way. In some instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the right-of-way grants. 35 Our interstate natural gas pipeline systems have federal eminent domain authority. Whether we have the power of eminent domain for the Pony Express crude oil pipeline varies from state to state, depending upon the laws of the particular state. Regardless, we must compensate landowners for the use of their property, which may include any loss of value to the remainder of their property not being used by us, which are sometimes referred to as "severance damages." Severance damages are often difficult to quantify and their amount can be significant. In eminent domain actions, such compensation may be determined by a court. Our inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our crude oil or natural gas pipeline systems are located. Our operations are dependent on our rights and ability to receive or renew the required permits and other approvals from governmental authorities and other third parties. Performance of our operations requires that we obtain and maintain numerous environmental and land use permits and other approvals authorizing our business activities. A decision by a governmental authority or other third party to deny, delay or restrictively condition the issuance of a new or renewed permit or other approval, or to revoke or substantially modify an existing permit or other approval, could have a material adverse effect on our ability to initiate or continue operations at the affected location or facility. Expansion of our existing operations is also predicated on securing the necessary environmental or land use permits and other approvals, which we may not receive in a timely manner or at all. In order to obtain permits and renewals of permits and other approvals in the future, we may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed pipeline or processing- related activities may have on the environment, individually or in the aggregate, including on public and Indian lands. Certain approval procedures may require preparation of archaeological surveys, endangered species studies and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements is expensive and significantly lengthens the time needed to develop a site or pipeline alignment. Also, obtaining or renewing required permits or other approvals is sometimes delayed or prevented due to community opposition and other factors beyond our control. The denial of a permit or other approval essential to our operations or the imposition of restrictive conditions with which it is not practicable or feasible to comply could impair or prevent our ability to develop or expand a property or right-of- way. Significant opposition to a permit or other approval by neighboring property owners, members of the public or non- governmental organizations, or other third parties or delay in the environmental review and permitting process also could impair or delay our ability to develop or expand a property or right-of-way. New legal requirements, including those related to the protection of the environment, could be adopted at the federal, state and local levels that could materially adversely affect our operations (including our ability to store, transport or process natural gas or crude oil or the pace of storing, transporting or processing natural gas or crude oil), our cost structure or our customers’ ability to use our services. Such current or future regulations could have a material adverse effect on our business and we may not be able to obtain or renew permits or other approvals in the future. A shortage of skilled labor in the midstream industry could reduce labor productivity and increase costs, which could have a material adverse effect on our business and results of operations. The transportation, storage and processing of natural gas, the transportation of crude oil and the fractionation of NGLs requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially and adversely affected. If our labor prices increase or if we experience materially increased health and benefit costs for employees, our results of operations could be materially and adversely affected. If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units. Upon the completion of our initial public offering, we became subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 requires us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting (except for the requirement for an auditor’s attestation report, as described below). Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm's, conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units. 36 For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements that apply to other public companies. In April 2012, President Obama signed into law the Jumpstart Our Business Startups Act, or the JOBS Act. For as long as we remain an "emerging growth company" as defined in the JOBS Act, we intend to continue taking advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act and reduced disclosure obligations regarding executive compensation in our periodic reports. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700 million in market value of our limited partner interests held by non-affiliates on the last business day of the most recently completed second fiscal quarter, or issue more than $1.0 billion of non-convertible debt over a three-year period. To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our common units to be less attractive as a result, there may be a less active trading market for our common units and our trading price may be more volatile. Our election to take advantage of the JOBS Act extended accounting transition period may make our financial statements more difficult to compare to other public companies. Pursuant to the JOBS Act, as an "emerging growth company," we must make an election to opt in or opt out of the extended transition period for any new or revised accounting standards that may be issued by the Public Company Accounting Oversight Board (PCAOB) or the SEC. We have elected to take advantage of such extended transition period which means that when a standard is issued or revised and it has different application dates for public or private companies, we can, for so long as we are an "emerging growth company," adopt the standard for private companies. This may make comparison of our financial statements with any other public company that either is not an "emerging growth company" or has opted out of using the extended transition period difficult or impossible as a result of our use of different accounting standards. The outcome of future rate cases will determine the amount of income taxes that we will be allowed to recover. In May 2005, the FERC issued a statement of general policy permitting a pipeline to include in its cost-of-service computations an income tax allowance provided that an entity or individual has an actual or potential income tax liability on income from the pipeline’s public utility assets. The extent to which owners of pipelines have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis in rate cases where the amounts of the allowances will be established. An adverse determination by the FERC with respect to this issue could have a material adverse effect on our revenues, earnings and cash flows. Our business could be negatively impacted by security threats, including cyber security threats, and related disruptions. We rely on our information technology infrastructure to process, transmit and store electronic information, including information we use to safely operate our assets. We may face cyber security and other security threats to our information technology infrastructure, which could include threats to our operational and safety systems that operate our pipelines, plants and assets. We could face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, "hacktivists," or private individuals. The age, operating systems or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cyber security threats. We could also face attempts to gain access to information related to our assets through attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations or information, otherwise known as "social engineering." Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-to-day operations. Breaches in our information technology infrastructure or physical facilities, or other disruptions, could result in damage to our assets, service interruptions, safety incidents, damage to the environment, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position, results of operations and prospects. If we are unable to protect our information and telecommunication systems against disruptions or failures, our operations could be disrupted. We rely extensively on computer systems to process transactions, maintain information and manage our business. Disruptions in the availability of our computer systems could impact our ability to service our customers and adversely affect our sales and results of operations. We are dependent on internal and third party information technology networks and systems, including the Internet and wireless communications, to process, transmit and store electronic information. Our computer systems are subject to damage or interruption due to system replacements, implementations and conversions, power outages, 37 computer or telecommunication failures, computer viruses, security breaches, catastrophic events such as fires, tornadoes, snowstorms and floods and usage errors by our employees. If our computer systems are damaged or cease to function properly, we may have to make a significant investment to fix or replace them, and we may have interruptions in our ability to service our customers. Although we attempt to eliminate or reduce these risks by using redundant systems, this disruption caused by the unavailability of our computer systems could nevertheless significantly disrupt our operations or may result in financial damage or loss due to, among other things, lost or misappropriated information. Risks Inherent in an Investment in Us Our general partner and its affiliates, including Tallgrass GP Holdings, which owns our general partner and the general partner of Tallgrass Development, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our other common unitholders. Tallgrass GP Holdings owns our general partner and appoints all of the officers and directors of our general partner. Tallgrass GP Holdings also owns and controls the general partner of Tallgrass Development. All of our current officers and a majority of the current directors of our general partner are also officers and/or directors of Tallgrass GP Holdings. Certain of our directors are also officers or principals of Kelso or EMG, whose affiliated entities, along with certain members of our management, own and control Tallgrass GP Holdings. Although our general partner has a duty to manage us in a manner that is beneficial to us and our unitholders, the officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner that is in the best interests of its owner, Tallgrass GP Holdings. Conflicts of interest will arise between our general partner and its owners, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its owners over our interests and the interests of our unitholders. These conflicts include the following situations, among others: • Neither our partnership agreement nor any other agreement requires Tallgrass GP Holdings or its owners to pursue a business strategy that favors us, and the officers and directors of Tallgrass GP Holdings have a fiduciary duty to make these decisions in the best interests of Tallgrass GP Holdings and its owners, which may be contrary to our interests. Tallgrass GP Holdings may choose to shift the focus of its investment and growth to areas not served by our assets. • Tallgrass GP Holdings, its owners, and their respective affiliates are not limited in their ability to compete with us and, other than Tallgrass Development’s obligation to offer us certain assets (if Tallgrass Development decides to sell such assets) pursuant to the right of first offer under the Omnibus Agreement, may offer business opportunities or sell midstream assets to third parties without first offering us the right to bid for them. • Our general partner is allowed to take into account the interests of parties other than us, such as Tallgrass GP Holdings, its owners, and their respective affiliates in resolving conflicts of interest and exercising certain rights under our partnership agreement, which has the effect of limiting its duty to our unitholders. • All of the current officers and a majority of the current directors of our general partner are also officers and/or directors of Tallgrass GP Holdings and will owe fiduciary duties to Tallgrass GP Holdings. The officers of our general partner are also officers of the general partner of Tallgrass Development and will devote significant time to the business of Tallgrass Development. • Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty. • Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval. • Disputes may arise under our commercial agreements with Tallgrass Development and its affiliates. • Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash available for distribution to our unitholders. • Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion or investment capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders. • Our general partner determines which costs incurred by it are reimbursable by us. • Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions. 38 • Our partnership agreement permits us to classify up to $40 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our general partner units or to our general partner in respect of the IDRs. • Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf. • Our general partner may limit its liability regarding our contractual and other obligations. • Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units. • Our general partner controls the enforcement of the obligations that it and its affiliates owe to us, including Tallgrass Development’s and its affiliates’ obligations under the Omnibus Agreement and their commercial agreements with us. • Our general partner decides whether to retain separate counsel, accountants or others to perform services for us. • Our general partner may transfer its IDRs without unitholder approval. • Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s IDRs without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations. Affiliates of our general partner are not limited in their ability to compete with us and have limited obligations to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect our results of operations and cash available for distribution to our unitholders. Affiliates of our general partner, including Kelso, EMG, Tallgrass GP Holdings and its direct and indirect subsidiaries, including Tallgrass Development, are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, in the future, affiliates of our general partner and the entities owned or controlled by affiliates of our general partner, including Tallgrass Development, may acquire, construct or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities, other than Tallgrass Development’s obligation to offer us certain assets (if Tallgrass Development decides to sell such assets) pursuant to the right of first offer under the Omnibus Agreement. While affiliates of our general partner may offer us the opportunity to buy these or other additional assets, these affiliates of our general partner, including Tallgrass Development, are not contractually obligated to do so, other than as described above, and we are unable to predict whether or when such opportunities may arise. Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner, its executive officers and directors or any of its affiliates, including Tallgrass Development. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner, including Tallgrass Development, and result in less than favorable treatment of us and our common unitholders. Reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our common unitholders. The amount and timing of such reimbursements will be determined by our general partner. Under our partnership agreement and the Omnibus Agreement, we will reimburse our general partner and Tallgrass Development’s general partner and its affiliates for certain expenses incurred on our behalf, including administrative costs, such as compensation expense for those persons who provide services necessary to run our business, and insurance expenses. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and Tallgrass Development’s general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders. 39 Our partnership agreement requires that we distribute our available cash, which could limit our ability to grow and make acquisitions. Our partnership agreement requires us to distribute our available cash to our unitholders. Accordingly, we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we intend to distribute our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement, and we do not anticipate there being limitations in our revolving credit facility, on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders. While our partnership agreement requires us to distribute our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. While our partnership agreement requires us to distribute our available cash, our partnership agreement, including provisions requiring us to make cash distributions therein, may be amended. Our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by our general partner and its affiliates, including Tallgrass Development). Tallgrass Development currently owns approximately 54% of our outstanding common units. The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements. Our common units are listed on the NYSE. Unlike most corporations, we are not required by NYSE rules to have, and we do not intend to have, a majority of independent directors on our general partner’s board of directors or a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. If you are not an eligible taxable holder, you will not be entitled to allocations of income or loss or distributions or voting rights on your common units and your common units will be subject to redemption. In order to avoid any material adverse effect on the maximum applicable rates that can be charged to customers by our subsidiaries on assets that are subject to rate regulation by the FERC or an analogous regulatory body, we have adopted certain requirements regarding those investors who may own our common units. Eligible holders are individuals or entities subject to United States federal income taxation on the income generated by us or entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. If a holder of our common units (other than affiliates of our general partner) is not a person who fits the requirements to be an eligible taxable holder, such holder will not receive allocations of income or loss or distributions or voting rights on its units and will run the risk of having its units redeemed by us at the market price calculated in accordance with our partnership agreement as of the date of redemption. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties. Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replace those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing (which provides that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action). This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include: • how to allocate business opportunities among us and its affiliates; 40 • whether to exercise its limited call right; • whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner; • how to exercise its voting rights with respect to the units it owns; • whether to elect to reset target distribution levels; • whether to transfer the IDRs or any units it owns to a third party; and • whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to the partnership agreement. In addition, our partnership agreement provides that any construction or interpretation of our partnership agreement and any action taken pursuant thereto or any determination, in each case, made by our general partner in good faith, shall be conclusive and binding on all unitholders. Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that: • whenever our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in the best interests of our partnership, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity; • • our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith; our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and • our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is: * * * * approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates; determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us. In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the last two bullets above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. 41 Holders of our common units have limited voting rights and are not entitled to select our general partner or elect members of its board of directors. Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders have no right on an annual or ongoing basis to select our general partner or elect its board of directors. Rather, the board of directors of our general partner, including the independent directors, is appointed by Tallgrass GP Holdings, as a result of it owning our general partner, and not by our unitholders. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management. Even if holders of our common units are dissatisfied, they cannot currently remove our general partner without its consent. Unitholders are currently unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common units is required to remove our general partner. Tallgrass Development owns an aggregate of approximately 54% of our outstanding common units. This gives Tallgrass Development the ability to prevent the involuntary removal of our general partner. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner and does not include most cases of charges of poor management of the business. Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units. Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, persons who acquired such units with the prior approval of the board of directors of our general partner and transferees of any of the foregoing, provided such transferee is an affiliate of the transferor, cannot vote on any matter. Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent. Our general partner may transfer its general partner interest to a third party without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Tallgrass GP Holdings to transfer all or a portion of its ownership interest in our general partner to a third party. For example, on January 28, 2015 Tallgrass GP Holdings announced that it intends to file a registration statement with the SEC for an initial public offering of equity interests in a newly formed entity that is expected to own, directly or indirectly, all of our incentive distribution rights, our general partner interest, and a certain number of our common units. If Tallgrass GP Holdings no longer controls, directly or indirectly, our general partner, then a third party with a controlling interest in our general partner would be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers. This effectively permits a "change of control" without the vote or consent of the unitholders. The IDRs of our general partner may be transferred to a third party without unitholder consent. Our general partner may transfer its IDRs to a third party at any time without the consent of our unitholders. If our general partner transfers its IDRs to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its IDRs. For example, a transfer of IDRs by our general partner could reduce the likelihood of Tallgrass Development selling or contributing additional midstream assets to us, as Tallgrass Development would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base. We may issue additional units without unitholder approval, which could negatively impact unitholders’ existing ownership interests. Our partnership agreement does not limit the number of additional limited partner interests that, including limited partner interests that rank senior to the common units, we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank could have the following effects: • • • our existing unitholders’ proportionate ownership interest in us will decrease; the amount of cash available for distribution on each unit may decrease; because the amount payable to holders of IDRs is based on a percentage of the total cash available for distribution, the distributions to holders of IDRs will increase even if the per unit distribution on common units remains the same; 42 • • • the ratio of taxable income to distributions may increase; the relative voting strength of each previously outstanding unit may be diminished; and the market price of the common units may decline. Affiliates of our general partner, including Tallgrass Development, may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units. Tallgrass Development currently holds 26,355,480 common units. In addition, we have agreed to provide our general partner and its affiliates with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop. For additional information, see Note 11 - Partnership Equity and Distributions to our Consolidated Financial Statements in Item 8.—Financial Statements and Supplementary Data in this Form 10-K. Our general partner may limit its liability regarding our obligations. Our general partner may limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement permits our general partner to limit its liability, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders. Our general partner has a limited call right that may require unitholders to sell units at an undesirable time or price. If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, unitholders may be required to sell common units at an undesirable time or price and may not receive any return on investment. Unitholders may also incur a tax liability upon a sale of your units. Tallgrass Development, an affiliate of our general partner, currently owns approximately 54% of our outstanding common units. Our general partner, or any transferee holding a majority of the IDRs, may elect to cause us to issue common units to it in connection with a resetting of the minimum quarterly distribution and the target distribution levels related to the IDRs, without the approval of the conflicts committee of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations. The holder or holders of a majority of the IDRs, which is currently our general partner, have the right, at any time when there are no subordinated units outstanding and the holders have received incentive distributions at the highest level to which they are entitled (48%) for each of the prior four consecutive fiscal quarters (and the amount of each such distribution did not exceed adjusted operating surplus for each such quarter), to reset the minimum quarterly distribution and the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the "reset minimum quarterly distribution"), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution. Our general partner has the right to transfer the IDRs at any time, in whole or in part, and any transferee holding a majority of the IDRs shall have the same rights as our general partner with respect to resetting target distributions. 43 In the event of a reset of the minimum quarterly distribution and the target distribution levels, the holders of the IDRs will be entitled to receive, in the aggregate, the number of common units equal to that number of common units which would have entitled the holders to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions on the IDRs in the prior two quarters. Our general partner will also be issued the number of general partner units necessary to maintain its general partner interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not otherwise be sufficiently accretive to cash distributions per common unit. It is possible, however, that our general partner or a transferee could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its IDRs and may therefore desire to be issued common units rather than retain the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. This risk could be elevated if our IDRs have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels. Your liability may not be limited if a court finds that unitholder action constitutes control of our business. A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that: • we were conducting business in a state but had not complied with that particular state’s partnership statute; or • your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute "control" of our business. Unitholders may have liability to repay distributions that were wrongfully distributed to them. Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable both for the obligations of the transferor to make contributions to the partnership that were known to the transferee at the time of transfer and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non- recourse to the partnership are counted for purposes of determining whether a distribution is permitted. Tax Risks to Common Unitholders Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced. The anticipated after-tax economic benefit of an investment in the common units depends in part on our being treated as a partnership for federal income tax purposes. We have not requested, and except as described below, do not plan to request, a ruling from the Internal Revenue Service, or IRS, on this or any other tax matter affecting us. Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. For example, we would be treated as a corporation if less than 90% of our gross income for any taxable year consists of "qualifying income" within the meaning of Section 7704 of the Internal Revenue Code. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Our distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units. 44 Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us. If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders. Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such additional tax on us by a state will reduce the cash available for distribution to you. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us. The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations of applicable law, possibly on a retroactive basis. The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by legislative, judicial or administrative changes or interpretations of applicable law at any time. For example, from time to time, the President or members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such recent legislative proposal would have eliminated, and the President proposed in his recently issued budget proposal to eliminate, the qualifying income exception upon which we rely for our treatment as a partnership for federal income tax purposes. We are unable to predict whether any of these changes or any other proposals will be reintroduced or will ultimately be enacted or whether judicial or administrative interpretations of applicable law will change. Any such changes could negatively impact the value of an investment in our common units. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us. A unitholder will be treated as a partner to whom we will allocate taxable income which could be different in amount than the cash we distribute. A unitholder's allocable share of our taxable income will be taxable to the unitholder, which may require the payment of federal income taxes and, in some cases, state and local income taxes even if no cash distributions are received from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income. If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders. We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution. Tax gain or loss on the disposition of our common units could be more or less than expected. If you sell your common units, you will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized on any sale or other disposition of your common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. 45 Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them. Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will generally be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units. We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units. Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. A successful IRS challenge also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders. We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. A unitholder whose common units are loaned to a "short seller" to cover a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition. Because a unitholder whose common units are loaned to a "short seller" to cover a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units. We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units. In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction. A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions. 46 The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes. We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Tallgrass Development and its direct and indirect owners collectively own more than 50% of the total interests in our capital and profits. Therefore, transfers by them of all or a portion of their interests in us could result in a termination of our partnership for federal income tax purposes. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year if the termination occurs on a day other than December 31 and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in the unitholder's taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years. As a result of investing in our common units you will likely become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties. In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own property or conduct business in a number of states, most of which currently impose a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own property or conduct business in additional states that impose a personal income tax. It is your responsibility to file all federal, state and local tax returns. Compliance with and changes in tax laws could adversely affect our performance. We are subject to extensive tax laws and regulations, including federal and state income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional tax payments, as well as interest and penalties. We have a subsidiary that is treated as a corporation for federal income tax purposes and subject to corporate level income taxes and may conduct additional activities in taxable corporate subsidiaries in the future. Even though we (as a partnership for U.S. federal income tax purposes) are not subject to U.S. federal income tax, we have a subsidiary that is organized as a corporation for U.S. federal income tax purposes. Although this subsidiary has not previously generated any material income, this corporate subsidiary’s activities may increase, and we may elect to conduct additional activities in this corporate subsidiary or in additional subsidiaries treated as corporations for U.S. federal income tax purposes. For example, it is unclear whether our share of water business services income from Water Solutions will be treated as qualifying income. While we have not requested a ruling from the IRS that such income is qualifying income, we may request such a ruling in the future. If the IRS is unwilling or unable to provide a favorable ruling in a timely manner, and if it becomes necessary in order to preserve our status as a partnership, we may elect to conduct all or portions of our Water Solutions business in a taxable corporate subsidiary (see "Risk Factors - Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced."). 47 The taxable income, if any, of a subsidiary that is treated as a corporation for U.S. federal income tax purposes, is subject to corporate-level U.S. federal income taxes, which may reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS or other state or local jurisdictions were to successfully assert that this corporation has more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, the cash available for distribution could be further reduced. The income tax return filings positions taken by this corporate subsidiary require significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is also required in assessing the timing and amounts of deductible and taxable items. Despite our belief that the income tax return positions taken by this subsidiary are fully supportable, certain positions may be successfully challenged by the IRS, state or local jurisdictions. Item 1B. Unresolved Staff Comments None. Item 2. Properties A description of our properties is contained in Item 1.—Business, "Our Assets" of this Annual Report. Our principal executive offices are located at 4200 W. 115th Street, Suite 350, Leawood, KS 66211 and our telephone number is 913-928-6060. We own two office buildings in Lakewood, Colorado, with a portion being leased to a third party pursuant to a lease with an initial term through 2020. In addition, TEP leases its principal executive offices in Leawood, Kansas. TD pays a proportionate share of the costs to occupy the building to TEP pursuant to the Omnibus Agreement. Item 3. Legal Proceedings See Note 17 – Legal and Environmental Matters to the consolidated financial statements included in Part II—Item 8.— Financial Statements and Supplementary Data of this Annual Report, which is incorporated by reference into this Part I—Item 3 of this Annual Report. Item 4. Mine Safety Disclosures Not applicable. 48 PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Market Information Our common units have been listed on the New York Stock Exchange ("NYSE") under the symbol "TEP" since the completion of our IPO on May 17, 2013. The following table sets forth the high and low sales prices of the common units, as reported by the NYSE, as well as the amount of cash distributions per unit declared for the periods indicated: $ Quarter Ended December 31, 2014 ................... September 30, 2014................... June 30, 2014 ............................ March 31, 2014 ......................... December 31, 2013 ................... September 30, 2013................... June 30, 2013 ............................ March 31, 2013 ......................... High Low Distribution per Common Unit $ 45.49 47.04 40.22 36.49 27.74 24.00 22.91 N/A $ 33.83 37.90 34.50 25.25 23.00 21.12 20.53 N/A 0.4850 0.4100 0.3800 0.3250 0.3150 0.2975 0.1422 (1) N/A (1) The distribution declared in the second quarter of 2013 was prorated for the period from May 17, 2013 to June 30, 2013. Holders As of February 19, 2015, there were 3 unitholders of record of our common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of beneficial unitholders is greater than the number of holders of record. In addition, as of February 19, 2015, our general partner owned all 834,391 of our general partner units. Equity Compensation Plan See Item 12.—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters for information regarding our Equity Compensation Plan. Distributions of Available Cash General. Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute our available cash to unitholders of record on the applicable record date, as determined by our general partner. Definition of Available Cash. The term "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 our general partner to: provide for proper conduct of business; comply with applicable law or regulation, any of our debt instruments or other agreements; or provide funds for distribution to unitholders and to our general partner for any one or more of the next four quarters; • plus, if our 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. Minimum Quarterly Distribution. We intend to make cash distributions to the holders of common units on a quarterly basis in an amount equal to at least the minimum quarterly distribution, or MQD, of $0.2875 per unit or $1.15 per unit on an annualized basis, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. However, there is no guarantee that we will pay the MQD on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Our general partner has broad discretion to establish cash reserves that it 49 determines are necessary or appropriate to properly conduct our business. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to our unitholders, reserves to reduce debt or, as necessary, reserves to comply with the terms of any of our agreements or obligations. We will be prohibited from making any distributions to unitholders if it would cause an event of default or if an event of default exists under our credit agreement. General Partner Interest. Our general partner is currently entitled to approximately 1.7% of all quarterly distributions that we make prior to our liquidation. As of February 19, 2015 our general partner interest is represented by 834,391 general partner units. Our general partner has the right, but not the obligation, to contribute a proportional amount of capital to us to maintain its general partner interest, up to 2%. The general partner’s proportionate interest in these distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportional amount of capital to us to maintain its general partner interest. Incentive Distribution Rights. As quarterly distributions exceed the MQD and other higher target distribution levels, our general partner, as the holder of the IDRs, becomes entitled to increasing percentages (13%, 23% and 48%) of the distributions after the MQD and such higher target distribution levels have been achieved. For additional information, see Note 11 - Partnership Equity and Distributions to our Consolidated Financial Statements in Item 8.—Financial Statements and Supplementary Data in this Form 10-K. Conversion of Subordinated Units. Under the terms of our partnership agreement and upon the payment of our quarterly cash distribution to unitholders on February 13, 2015, our subordination period ended. As a result, our 16,200,000 subordinated units held by TD converted into common units on a one for one basis on February 17, 2015. The conversion of the subordinated units did not impact the aggregate amount of cash distributions paid. Performance Graph The following performance graph compares the performance of our common units with the NYSE Composite Index Total Return and the Alerian Total Return MLP Index during the period beginning on May 14, 2013, and ending on December 31, 2014. The graph assumes a $100 investment in our common units and in each of the indices at the beginning of the period and a reinvestment of distributions/dividends paid on such investments throughout the period. Recent Sales of Unregistered Equity Securities None. 50 Repurchase of Equity by Tallgrass Energy Partners, LP or Affiliated Purchasers None. Item 6. Selected Financial Data The historical financial statements included in this Annual 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." As discussed further in Note 2 – Summary of Significant Accounting Policies to the accompanying consolidated financial statements, the financial statements of our Predecessor for historical periods beginning after November 13, 2012 have been recast to reflect the operations of Trailblazer Pipeline Company LLC ("Trailblazer"), which was acquired on April 1, 2014, and Tallgrass Pony Express Pipeline, LLC ("Pony Express"), of which TEP acquired a controlling 33.3% membership interest effective September 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 term "TEP Pre-Predecessor" refers to the Tallgrass Energy Partners Pre-Predecessor, which represents the combined results of operations of TIGT and TMID that were owned by Kinder Morgan Energy Partners, LP ("TEP Pre-Predecessor Parent") prior to November 13, 2012, at which date TEP Pre-Predecessor Parent sold those assets, among others, to TD. Financial information for the TEP Pre-Predecessor has not been recast to reflect the operations of Trailblazer and Pony Express. 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, Trailblazer was owned by TD from November 13, 2012 to March 31, 2014, and Pony Express was wholly-owned by TD from November 13, 2012 to August 31, 2014. As used in this Annual 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 consolidated financial statements and related notes thereto included elsewhere in this Annual Report. A reference to a "Note" herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8.—Financial Statements. In addition, please read "Cautionary Statement Regarding Forward-Looking Statements" and "Risk Factors" for information regarding certain risks inherent in our business. The following table shows selected historical financial and operating data of TEP and TEP Pre-Predecessor for the periods and as of the dates indicated. The selected historical financial data for the year ended December 31, 2011 and for the period from January 1 through November 12, 2012 is derived from the audited books and records of TEP Pre-Predecessor. The selected historical financial data for the period from November 13, 2012 to December 31, 2012 and the years ended December 31, 2014 and 2013 are derived from the audited financial statements of TEP as recast for the acquisitions of Trailblazer and a 33.3% membership interest in Pony Express. We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, the consolidated financial statements and the accompanying notes included elsewhere in this Annual Report. 51 Our operating results incorporate a number of significant estimates and uncertainties. Such matters could cause the data included herein to not be indicative of our future financial condition or results of operations. A discussion of our critical accounting estimates is included in "Management’s Discussion and Analysis of Financial Condition and Results of Operations" in Item 7. TEP TEP Pre-Predecessor Year Ended December 31, 2014 Year Ended December 31, 2013 Period from November 13 to December 31, 2012 Period from January 1 to November 12, 2012 Year Ended December 31, 2011 (in thousands, except per unit amounts) (in thousands, except per unit amounts) Statement of operations data: Revenue............................................... $ Operating income ................................ $ Net income (loss) ................................ $ Net income (loss) attributable to partners................................................ $ Net income allocable to limited partners................................................ $ Net income per limited partner unit - basic .................................................... $ Net income per limited partner unit - diluted.................................................. $ 371,556 53,413 59,329 70,681 61,774 1.39 1.36 $ $ $ $ $ $ $ 290,526 33,999 7,624 9,747 $ $ $ $ 38,572 69 (2,618) (2,366) $ $ $ $ 220,292 50,113 51,496 51,496 $ $ $ $ 307,043 75,499 77,507 77,507 6,991 (1) 0.17 (1) 0.17 (1) N/A N/A N/A N/A N/A N/A N/A N/A N/A Balance sheet data (at end of period): Property, plant and equipment, net...... $ 1,853,081 Total assets .......................................... $ 2,457,197 Long-term debt.................................... $ 559,000 Long-term debt allocated from TD ..... $ $ 1,116,806 $ 726,754 $ 1,631,413 $ 1,238,598 $ $ 717,486 767,681 $ $ 719,009 772,896 $ 135,000 — $ — $ $ — $ 390,491 $ — $ — $ — — Other: Distributions declared per common unit ...................................................... $ 1.6000 $ 0.7547 N/A N/A N/A (1) The net income allocated to the limited partners was based upon the number of days between the closing of the IPO on May 17, 2013 to December 31, 2013. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Overview We are a publicly traded, growth-oriented Delaware limited partnership formed in 2013 to own, operate, acquire and develop midstream energy assets in North America. We currently provide natural gas transportation and storage services for customers in the Rocky Mountain and Midwest regions of the United States through the TIGT System and the Trailblazer Pipeline. We provide crude oil transportation to customers in Wyoming and the surrounding region, servicing the Bakken oil production area of North Dakota and eastern Montana through our membership interest in Pony Express, which owns the Pony Express System. We also provide services for customers in Wyoming at its Midstream Facilities, and we provide water business services to customers in Colorado and Texas through Water Solutions. Our operations are strategically located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford and Bakken shale formations. 52 We intend to continue to leverage our relationship with TD and utilize the significant experience of our management team to execute our growth strategy of acquiring midstream assets from TD and third parties, increasing utilization of our existing assets and expanding our systems through construction of additional assets. Our reportable business segments are: • Natural Gas Transportation & Logistics—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities; • Crude Oil Transportation & Logistics—the ownership and operation of a crude oil pipeline system; and • Processing & Logistics—the ownership and operation of natural gas processing, treating and fractionation facilities, as well as water business services provided primarily to the oil and gas exploration and production industry. Summary of Results for the Year Ended December 31, 2014 Net income attributable to partners for the year ended December 31, 2014 was $70.7 million, with Adjusted EBITDA and Distributable Cash Flow (each as defined below under "Non-GAAP Financial Measures") of $109.9 million and $96.1 million, respectively, compared to net income attributable to partners for the year ended December 31, 2013 of $9.7 million, with Adjusted EBITDA and Distributable Cash Flow of $78.4 million and $62.3 million, respectively. The increase in net income, Adjusted EBITDA, and Distributable Cash Flow was largely driven by our acquisition of a 33.3% membership interest in Pony Express, which was placed in service in October 2014, as discussed further under "Results of Operations" below. During 2014, we completed a follow-on public offering of 8,050,000 common units, as well as the acquisitions of a 100% membership interest in Trailblazer, a 33.3% membership interest in Pony Express, and an 80% interest in Water Solutions. In October 2014, we implemented an at-the-market ("ATM") offering program whereby we may sell newly issued common units to the public. As of December 31, 2014, we had issued 28,625 limited partner common units under our ATM program. Factors and Trends Impacting Our Business We expect to continue to be affected by certain key factors and trends described below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. See also Item 1A.—Risk Factors. Growth Associated with Acquisitions and Expansion Projects Growth associated with acquisitions We believe that we are well-positioned to grow through accretive acquisitions. We intend to pursue acquisition opportunities from third parties as they become available and expect to continue to acquire assets from TD’s portfolio of midstream assets, which include the remaining 66.7% ownership interest in Pony Express, Terminals and TD’s 50% interest in, and operation of, the REX Pipeline. Pursuant to the Omnibus Agreement, TD granted us the right of first offer to acquire each of the remaining Retained Assets if TD decides to sell those assets. Terminals is not a Retained Asset. Other than its obligations under the Omnibus Agreement, TD is under no obligation to offer to sell us additional assets or to pursue acquisitions jointly with us, and we are under no obligation to buy any assets from TD or pursue any such joint acquisitions. However, given the significant economic interest in us held by TD and its affiliates, we believe TD will be incentivized to offer us the opportunity to acquire its assets as each matures into an operating profile more conducive to our principal business objective of increasing the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business. On January 8, 2015, TEP announced that TD offered TEP the right to purchase an additional 33.3% membership interest in Pony Express. A Conflicts Committee of the Board of Directors of TEP’s general partner, consisting solely of independent directors, has been formed to evaluate the offer with assistance from external advisors to be engaged by the Conflicts Committee. No definitive transaction agreement has been executed at this time and the proposed transaction remains subject to review, negotiations and approval by the Conflicts Committee and by the board of directors of TEP’s general partner. Although it is uncertain when or if TD will offer us the opportunity to acquire the other Retained Assets, it is possible TD will offer us the opportunity to purchase its remaining membership interests in Pony Express at some point in the next 9-12 months, and all or a portion of its 50% interest in, and the operation of, the REX Pipeline thereafter. Growth associated with expansion projects As production and demand for our services increase in the areas that our operations are located, we believe that we are well positioned to increase volumes to our systems through cost-effective capacity expansions. For example, in 2013, we completed an expansion of our Casper and Douglas plants and increased processing capacity from approximately 138.5 MMcf/d to approximately 190 MMcf/d and fractionation capabilities from approximately 2,000 barrels per day to approximately 3,500 barrels per day. 53 In 2014, Pony Express completed the conversion and construction of its approximately 698-mile crude oil pipeline commencing in Guernsey, Wyoming, and terminating in Cushing, Oklahoma. Pony Express is also constructing an approximately 66-mile lateral in Northeast Colorado that will commence in Weld County, Colorado, and interconnect with the Pony Express System just east of Sterling, Colorado. That lateral is expected to be in service sometime during the first half of 2015. U.S. Crude Oil and Natural Gas Supply and Demand Dynamics Crude oil, natural gas and products derived from both continue to be critical components of energy supply and demand in the United States. Although crude oil and natural gas prices have declined in the latter part of 2014 and early 2015, we believe that the long-term prospects for continued crude oil and natural gas production increases are favorable and will be driven in part by increased domestic demand resulting from population and economic growth, higher industrial consumption in the U.S. and a desire to reduce domestic reliance on imports. We expect natural gas to continue to displace coal-fired electricity generation due to the low prices of natural gas and stricter environmental regulations on the mining and burning of coal. For additional information, please read Item 7A.-Quantitative and Qualitative Disclosures About Market Risk. Growth in Production from Shale Plays We expect productivity of oil and natural gas wells to continue increasing over the long-term in some basins across the United States because of the increasing precision and efficiency of horizontal drilling and hydraulic fracturing in oil and natural gas extraction. We believe that any production growth over time in the Wind River Basin and Powder River Basin will benefit our Midstream Facilities and, to a lesser extent, the TIGT System and Trailblazer Pipeline with increased throughput volumes. We also believe that increasing yields over time in the Bakken Shale and Denver-Julesburg Basin will benefit the Pony Express System, as well as the TIGT System and the Trailblazer Pipeline. Finally, despite recent decreases in crude oil and natural gas prices, we also believe that there may even be short term growth in production, as producers will likely try to maximize revenue from existing production activity. Interest Rates The credit markets recently have experienced near-record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. If this occurs, interest rates on floating rate credit facilities and future offerings in the debt capital markets could be higher than current levels, causing our financing costs to increase accordingly. In addition, there is a financing cost for the storage capacity user to carry the cost of the inventory while it is stored in the facility. That financing cost is impacted by the cost of capital or interest rate incurred by the storage user as well as the commodity cost of the natural gas in inventory. The higher the financing cost, the lower the margin that will remain from the price spread that was intended to be captured. Accordingly, a significant increase in interest rates could impact the demand for storage capacity independent of other market fundamentals. For additional information, please read Item 7A.-Quantitative and Qualitative Disclosures About Market Risk. Rising Operating Costs and Inflation The high level of crude oil and natural gas exploration, development and production activities during the past several years across the United States has resulted in increased competition for personnel and equipment. Even with lower crude oil prices, as discussed above there may still be short term production growth, which leads to competition for skilled workers. This may ultimately increase the prices we pay for labor, supplies, property and equipment. An increase in the general level of prices in the economy could have a similar effect. We may be unable to recover all of these increased costs from our customers. To the extent we are unable to procure necessary supplies or recover higher costs, our operating results will be negatively impacted. Recent Developments GP Holdings Registration Statement On January 28, 2015, Tallgrass GP Holdings, which owns the general partners of TD and TEP, announced that it intends to file a registration statement with the SEC for an initial public offering of equity interests in a newly formed entity that is expected to own, directly or indirectly, all of TEP’s incentive distribution rights, TEP’s general partner interest, and a certain number of common units representing limited partner interests in TEP. 54 Potential Acquisition Pursuant to the right of first offer in the Omnibus Agreement executed between TEP and TD in connection with our initial public offering in May 2013, TD has offered us the right to purchase an additional 33.3% membership interest in Pony Express. If consummated, this transaction would increase our membership interest in Pony Express to 66.7%. Terms of the offer have not been finalized. A Conflicts Committee of the board of directors of our general partner, consisting solely of independent directors, has been formed to evaluate the offer with assistance from external advisors to be engaged by the Conflicts Committee. No definitive transaction agreement has been executed at this time and the proposed transaction remains subject to review, negotiations and approval by the Conflicts Committee and by the board of directors of TEP’s general partner. In conjunction with the proposed transaction, the parties made required filings under the Hart-Scott-Rodino Antitrust Improvements Act and the waiting period for consummating the transaction has terminated. How We Evaluate Our Operations We evaluate our results using, among other measures, contract profile 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 Profile and Volumes Our results are driven primarily by the volume of crude oil transportation capacity under firm contracts, the volume of natural gas transportation and storage capacity under firm contracts, the volume of natural gas that we process and the fees assessed for such services. Operating Costs and Expenses The primary components of our operating costs and expenses that we evaluate include cost of sales 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. 55 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, plus preferred distributions received from Pony Express in excess of its distributable cash flow attributable to our net interest and adjusted for deficiency payments received from or utilized by Pony Express shippers, less cash interest expense, maintenance capital expenditures, and distributions to noncontrolling interests in excess of earnings allocated to noncontrolling interests, to analyze our performance. Maintenance capital expenditures are cash expenditures incurred (including expenditures for the construction or development of new capital assets) that we expect to maintain our long-term operating income or operating capacity. These expenditures typically include certain system integrity, compliance and safety improvements. TEP receives a minimum quarterly preference payment from Pony Express of $16.65 million through the quarter ending September 30, 2015 (prorated to approximately $5.4 million for the quarter ended September 30, 2014). To the extent that Pony Express does not have sufficient distributable cash flow to cover this preference payment, TD, as the noncontrolling interest owner, is required to contribute cash to Pony Express to fund the excess preference payment. The cash received by Pony Express from TD to fund the minimum quarterly preference payment in excess of distributable cash flow from Pony Express is considered distributable cash flow at TEP. Pony Express collects deficiency payments for barrels committed by the customer to be transported in a month but not physically received for transport or delivered to the customers' agreed upon destination point. These deficiency payments are recorded as a deferred liability until the barrels are physically transported and delivered by TEP. As discussed further in Note 2 – Summary of Significant Accounting Policies, earnings at Pony Express are allocated between TEP and noncontrolling interests in accordance with a substantive profit sharing arrangement rather than pro rata by ownership. Distributions made by Pony Express to its noncontrolling interests reduce the distributable cash flow available to TEP. 56 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: TEP TEP Pre-Predecessor Year Ended December 31, 2014 Year Ended December 31, 2013 (in thousands) Period from November 13 to December 31, 2012 Period from January 1 to November 12, 2012 (in thousands) Reconciliation of Adjusted EBITDA to Net Income Net Income (Loss) attributable to partners................................... $ Add: 70,681 $ 9,747 $ (2,366) $ 51,496 Interest expense (income), net of noncontrolling interest..... 7,648 11,035 3,179 Depreciation and amortization expense, net of noncontrolling interest .......................................................... Loss on extinguishment of debt ............................................ Non-cash (gain) loss related to derivative instruments ......... Non-cash compensation expense .......................................... Distributions from unconsolidated investment ..................... Gain on remeasurement of unconsolidated investment ........ Texas Margin Tax.................................................................. 45,389 — (184) 5,136 1,464 (9,388) — Less: Non-cash loss allocated to noncontrolling interest ............... (10,151) (717) Adjusted EBITDA ...................................................................... $ 109,878 Equity in earnings of unconsolidated investment ................. 37,898 17,526 386 1,798 — — — — 5,197 — (273) — — — — — — 78,390 $ $ — 5,737 $ (1,661) 20,647 — — — — — 279 — — 70,761 Reconciliation of Adjusted EBITDA and Distributable Cash Flow to Net Cash Provided by Operating Activities Net cash provided by operating activities .................................... $ Add: 79,444 $ 82,482 $ 10,464 $ 81,335 Interest expense (income), net of noncontrolling interest..... Texas Margin Tax.................................................................. 7,648 — Other, including changes in operating working capital......... 22,786 Adjusted EBITDA ...................................................................... $ 109,878 Add: $ 11,035 — (15,127) 78,390 $ 3,179 — (7,906) 5,737 $ (1,661) 279 (9,192) 70,761 Pony Express preferred distributions in excess of distributable cash flow attributable to Pony Express ............ Pony Express deficiency payments....................................... Less: Maintenance capital expenditures ......................................... Cash interest expense ............................................................ Distributions to noncontrolling interest ................................ Cash flow attributable to predecessor operations.................. Distributable Cash Flow ............................................................ $ 5,429 5,378 (9,913) (6,266) (5,361) (3,086) 96,059 — — (15,951) (3,555) — 3,367 62,251 $ 57 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: TEP TEP Pre-Predecessor Year Ended December 31, 2014 Year Ended December 31, 2013 (in thousands) Period from November 13 to December 31, 2012 Period from January 1 to November 12, 2012 (in thousands) Reconciliation of Adjusted EBITDA to Operating Income in the Natural Gas Transportation & Logistics Segment (1) Operating income (loss) ............................................................ $ 40,887 Add: Depreciation and amortization expense ............................. Other income ...................................................................... Non-cash (gain) loss related to derivative instruments ...... 23,788 (184) 3,102 Segment Adjusted EBITDA.................................................... $ 67,593 Reconciliation of Adjusted EBITDA to Operating Income in the Crude Oil Transportation & Logistics Segment (1) Operating income (loss) ............................................................ $ Add: 3,601 Depreciation and amortization expense, net of noncontrolling interest........................................................ 10,553 Adjusted EBITDA attributable to noncontrolling interests 1,557 Segment Adjusted EBITDA.................................................... $ 15,711 Reconciliation of Adjusted EBITDA to Operating Income in the Processing & Logistics Segment (1) Operating income ...................................................................... $ 20,577 Add: $ 24,040 $ (1,474) $ 34,563 30,169 386 2,226 $ 56,821 $ 4,248 (273) 492 2,993 $ 17,895 — 1 52,459 $ (3,156) $ (378) $ 1,009 2,104 126 252 $ (43) $ — $ — — — — $ 16,472 $ 1,921 $ 15,550 Depreciation and amortization expense, net of noncontrolling interest........................................................ 11,048 6,720 Distributions from unconsolidated investment .................. 1,464 Segment Adjusted EBITDA.................................................... $ 33,089 Total Segment Adjusted EBITDA.......................................... $ 116,393 (2,500) (4,015) Total Adjusted EBITDA.......................................................... $ 109,878 Public company costs ......................................................... Elimination of intersegment activity .................................. — $ 23,192 $ 79,970 (1,580) — $ 78,390 $ $ $ 823 — 2,744 5,737 — — 5,737 $ $ $ 2,752 — 18,302 70,761 — — 70,761 (1) Segment results as presented represent total operating income and Adjusted EBITDA, including intersegment activity, for the Natural Gas Transportation & Logistics, Crude Oil Transportation & Logistics, and Processing & Logistics segments. For reconciliations to the consolidated financial data, see Note 18 – Reporting Segments to the accompanying consolidated financial statements. 58 Results of Operations The following provides a summary of our consolidated results of operations for the periods indicated: TEP TEP Pre-Predecessor (1) Year Ended December 31, 2014 Year Ended December 31, 2013 Period from November 13 to December 31, 2012 (in thousands, except operating data) Period from January 1 to November 12, 2012 (in thousands, except operating data) Revenues: Natural gas liquids sales............................................ $ Natural gas sales........................................................ Natural gas transportation services ........................... Crude oil transportation services............................... Processing and other revenues .................................. Total Revenues ................................................ Operating Costs and Expenses: 170,924 $ 146,313 $ 18,554 $ 106,355 10,325 126,733 28,343 35,231 371,556 9,387 120,025 — 14,801 290,526 2,326 15,970 — 1,722 38,572 Cost of sales and transportation services .................. 191,654 146,154 19,050 Operations and maintenance ..................................... Depreciation and amortization .................................. General and administrative ....................................... Taxes, other than income taxes ................................. Total Operating Costs and Expenses............... Operating Income ............................................................. Other (Expense) Income: Interest (expense) income, net.......................................... Gain on remeasurement of unconsolidated investment.... Loss on extinguishment of debt ....................................... Equity in earnings of unconsolidated investment ............ Other income, net ............................................................. Total Other Income (Expense) ......................................... Net Income (Loss) Before Taxes...................................... Texas Margin Taxes................................................... Net Income (Loss) ............................................................ Net loss attributable to noncontrolling interests ....... Net Income (Loss) attributable to partners....................... 39,577 47,048 33,160 6,704 318,143 53,413 (7,292) 9,388 — 717 3,103 5,916 59,329 — 59,329 11,352 70,681 35,404 39,917 27,651 7,401 256,527 33,999 (11,054) — (17,526) — 2,205 (26,375) 7,624 — 7,624 2,123 9,747 3,921 5,449 8,806 1,277 38,503 69 (3,179) — — — 492 (2,687) (2,618) — (2,618) 252 (2,366) 15,634 93,214 — 5,089 220,292 101,452 29,901 20,647 11,318 6,861 170,179 50,113 1,661 — — — 1 1,662 51,775 279 51,496 — 51,496 Other Financial Data (2) Adjusted EBITDA............................................................ $ 109,878 $ 78,390 $ 5,737 $ 70,761 Operating Data Gas transportation firm contracted capacity (Mmcf/d) .... Crude oil transportation average throughput (Bbls/d)(3)... Natural gas processing inlet volumes (Mmcf/d) .............. 1,537 85,229 152 1,411 N/A 133 1,383 N/A 127 762 N/A 122 (1) As discussed further in Note 2 – Summary of Significant Accounting Policies to the accompanying consolidated financial statements, financial information for the TEP Pre-Predecessor has not been recast to reflect the operations of Trailblazer and the 33.3% membership interest in Pony Express. (2) 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. 59 (3) Approximate average daily throughput for the year ended December 31, 2014 is reflective of the volumetric ramp up due to commercial in-service of the Pony Express System beginning in October 2014 and delays in the construction and expansion efforts of third-party pipelines with which Pony Express shares joint tariffs. Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013 Revenues. Total revenues were $371.6 million for the year ended December 31, 2014, compared to $290.5 million for the year ended December 31, 2013, which represents an increase of $81.0 million, or 28%, in total revenues. Revenue in the Natural Gas Transportation & Logistics segment increased $12.2 million, or 10%, while revenues in the Processing & Logistics segment increased $43.8 million, or 27%. There were revenues of $28.3 million in the Crude Oil Transportation & Logistics segment for the year ended December 31, 2014, but no revenues in that segment for the year ended December 31, 2013 as Pony Express had not yet commenced commercial operations. Operating costs and expenses. Operating costs and expenses were $318.1 million for the year ended December 31, 2014 compared to $256.5 million for the year ended December 31, 2013, which represents an increase of $61.6 million, or 24%. The increase in operating costs and expenses is a result of increased costs of $39.7 million in the Processing & Logistics segment primarily driven by increased cost of sales and transportation services of $32.0 million, higher depreciation and amortization of $4.5 million and higher operations and maintenance of $2.7 million, and increased costs of $21.6 million in the Crude Oil & Logistics segment due to the start of commercial operations at Pony Express in October 2014. The increased costs in the Processing & Logistics and Crude Oil & Logistics segments were partially offset by decreased costs of $4.6 million in the Natural Gas Transportation & Logistics segment primarily driven by lower depreciation and amortization of $6.4 million and lower general and administrative expenses of $3.8 million, partially offset by higher cost of sales and transportation services of $5.8 million. Interest (expense) income, net. Interest expense of $7.3 million for the year ended December 31, 2014 was primarily composed of interest and fees associated with TEP’s revolving credit facility, partially offset by interest income of $1.5 million on the cash balance swept to TD under the Pony Express cash management agreement. Interest expense of $11.1 million for the year ended December 31, 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, as well as interest and fees associated with TEP's revolving credit facility. Gain on remeasurement of unconsolidated investment. Gain on remeasurement of unconsolidated investment of $9.4 million for the year ended December 31, 2014 was related to the remeasurement to fair value of our original 50% equity investment in Grasslands Water Services I, LLC ("GWSI") in connection with TEP's consolidation of the Water Solutions business on May 13, 2014. Loss on extinguishment of debt. Loss on extinguishment of debt of $17.5 million for the year ended December 31, 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 year ended December 31, 2014 was related to our investment in GWSI prior to TEP's consolidation of the Water Solutions business on May 13, 2014. Other income, net. Other income, net typically includes rental income, income earned from certain customers related to the capital costs we incurred to connect these customers to our system, the allowance for funds used during construction at our regulated entities, and other noncash gains and losses. Other income for the year ended December 31, 2014 was $3.1 million compared to $2.2 million for the year ended December 31, 2013. Year Ended December 31, 2013 Compared to the Period from January 1, 2012 to November 12, 2012 Revenues. Total revenues were $290.5 million for the year ended December 31, 2013, compared to $220.3 million for the period from January 1, 2012 to November 12, 2012, which represents a 15% increase in average monthly revenues. Average monthly revenues in the Natural Gas Transportation & Logistics segment increased 7% while average monthly revenues in the Processing & Logistics segment increased 22%. Operating costs and expenses. Operating costs and expenses were $256.5 million for the year ended December 31, 2013 compared to $170.2 million for the period from January 1, 2012 to November 12, 2012, which represents a 31% increase in average monthly operating costs and expenses. Cost of sales and transportation services were $146.2 million for the year ended December 31, 2013 compared to $101.5 million for the period from January 1, 2012 to November 12, 2012, which represents a 25% increase in average monthly cost of sales and transportation services. Average monthly cost of sales and transportation services increased 27% in the Processing & Logistics segment and 17% in the Natural Gas Transportation & Logistics segment. 60 Operations and maintenance costs were $35.4 million for the year ended December 31, 2013 compared to $29.9 million for the period from January 1, 2012 to November 12, 2012, which represents a 3% increase in average monthly operations and maintenance costs driven by a 7% increase in average operations and maintenance in the Natural Gas Transportation & Logistics segment, partially offset by an 8% decrease in average operations and maintenance in the Processing & Logistics segment. Depreciation and amortization was $39.9 million for the year ended December 31, 2013 compared to $20.6 million for the period from January 1, 2012 to November 12, 2012, which represents a 68% increase in average monthly depreciation and amortization. Average monthly depreciation and amortization in the Natural Gas Transportation & Logistics and Processing & Logistics segments increased 46% and 112%, respectively. In addition, depreciation and amortization of $3.0 million was recognized in the Crude Oil Transportation & Logistics segment during the year ended December 31, 2013. General and administrative expenses during the year ended December 31, 2013 were $27.7 million compared to $11.3 million for the period from January 1, 2012 to November 12, 2012, which represents a 112% increase in average monthly general and administrative expenses. Average monthly general and administrative expenses in the Natural Gas Transportation & Logistics and Processing & Logistics segments increased 99% and 33%, respectively. In addition, general and administrative expenses of $0.1 million was recognized in the Crude Oil Transportation & Logistics segment during the year ended December 31, 2013. Taxes, other than income taxes, were $7.4 million for the year ended December 31, 2013 compared to $6.9 million for the period from January 1, 2012 to November 12, 2012 which represents a 6% decrease in average monthly taxes, other than income taxes. Taxes, other than income taxes, decreased 13% in the Processing & Logistics segment and 6% in the Natural Gas Transportation & Logistics segment. Interest (expense) income, net. Interest expense of $11.1 million for the year ended December 31, 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, as well as interest and fees associated with TEP's revolving credit facility. Loss on extinguishment of debt. The loss on extinguishment of debt of $17.5 million during the year ended December 31, 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. Other income, net. Other income, net for the year ended December 31, 2013 was $2.2 million compared to a negligible amount for the period from January 1, 2012 to November 12, 2012. Other income for the year ended December 31, 2013 primarily relates to rental income and a gain related to the favorable elimination of a liability associated with a small inactive storage field. Texas Margin Tax. During 2012, TEP Pre-Predecessor incurred Texas Margin Taxes because it was a part of an affiliated group that generated sales in the State of Texas. Year Ended December 31, 2013 Compared to the Period from November 13, 2012 to December 31, 2012 Revenues. Total revenues were $290.5 million for the year ended December 31, 2013, compared to $38.6 million for the period from November 13, 2012 to December 31, 2012, which represents consistent average monthly revenues for the periods across all segments. Operating costs and expenses. Operating costs and expenses were $256.5 million for the year ended December 31, 2013 compared to $38.5 million for the period from November 13, 2012 to December 31, 2012, which represents a 12% decrease in average monthly operating costs and expenses. The overall decrease in average monthly operating costs and expenses was driven by a 59% decrease in general and administrative expenses, primarily in the Natural Gas Transportation & Logistics and Processing & Logistics segments. Interest (expense) income, net. Interest expense of $11.1 million for the year ended December 31, 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, as well as interest and fees associated with TEP's revolving credit facility. Interest expense of $3.2 million for the period from November 13, 2012 to December 31, 2012 represents the interest expense related to the $400 million term loan allocated to TEP from TD. Loss on extinguishment of debt. The loss on extinguishment of debt of $17.5 million during the year ended December 31, 2013 represents the loss associated with the write off of deferred financing costs and unamortized discounts associated with the repayment of debt allocated to TEP from TD. 61 Other income (expense), net. Other income for the year ended December 31, 2013 was $2.2 million compared to $0.5 million for the period from November 13, 2012 to December 31, 2012. Other income for the year ended December 31, 2013 primarily relates to rental income and a gain related to the favorable elimination of a liability associated with a small inactive storage field. Other income for the period from November 13, 2012 to December 31, 2012 primarily relates to rental income. The following provides a summary of our Natural Gas Transportation & Logistics segment results of operations for the periods indicated: Segment Financial Data - Natural Gas Transportation & Logistics (1) Year Ended December 31, 2014 Year Ended December 31, 2013 Period from November 13 to December 31, 2012 Period from January 1 to November 12, 2012 TEP TEP Pre-Predecessor (2) (in thousands) (in thousands) Revenues: Natural gas sales ..................................................... $ Natural gas transportation services......................... 7,868 $ 5,906 $ 624 $ 131,990 121,945 16,066 Processing and other revenues................................ 222 26 6 Total revenues ............................................... 140,080 127,877 16,696 Operating costs and expenses: Cost of sales and transportation services ................ Operations and maintenance................................... Depreciation and amortization................................ General and administrative ..................................... Taxes, other than income taxes............................... Total operating costs and expenses ............... Operating income (loss)................................................. $ Segment Adjusted EBITDA........................................... $ 25,115 27,422 23,788 16,767 6,101 99,193 40,887 67,593 19,293 26,682 30,169 20,604 7,089 103,837 $ $ 24,040 56,821 $ $ 2,312 3,040 4,248 7,335 1,235 18,170 (1,474) 2,993 $ $ 9,814 93,910 278 104,002 14,378 21,625 17,895 8,994 6,547 69,439 34,563 52,459 (1) Segment results as presented represent total revenue and Adjusted EBITDA, including intersegment activity. For reconciliations to the consolidated financial data, see Note 18 – Reporting Segments to the accompanying consolidated financial statements. (2) As discussed further in Note 2 – Summary of Significant Accounting Policies to the accompanying consolidated financial statements, financial information for the TEP Pre-Predecessor has not been recast to reflect the operations of Trailblazer. Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013 Revenues. Natural Gas Transportation & Logistics segment revenues were $140.1 million for the year ended December 31, 2014, compared to $127.9 million for the year ended December 31, 2013, which represents a $12.2 million, or 10%, increase in segment revenues. The increase in segment revenues was driven by a $10.0 million increase in transportation services revenue primarily due to increased volumes at Trailblazer and increased fuel reimbursements as a result of higher prices at TIGT, and a $2.0 million increase in natural gas sales primarily due to 38% higher prices, partially offset by decreased volumes. Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation & Logistics segment were $99.2 million for the year ended December 31, 2014 compared to $103.8 million for the year ended December 31, 2013, which represents a decrease of $4.6 million, or 4%. Cost of sales and transportation services increased $5.8 million, or 30%, in the year ended December 31, 2014 when compared to the same period in the prior year, due to increased costs of $9.3 million at TIGT primarily driven by increased fuel reimbursements and gas purchases, partially offset by decreased costs of $3.5 million at Trailblazer driven by lower fuel costs in 2014 as a result of the Trailblazer rate case settlement. Operations and maintenance costs increased $0.7 million, or 3%, in the year ended December 31, 2014 when compared to the same period in the prior year, primarily driven by increased costs associated with repairs and maintenance activities and pipeline compliance requirements at Trailblazer during the year ended December 31, 2014, partially offset by lower costs related to the timing of pipeline integrity projects at TIGT. 62 Depreciation and amortization decreased $6.4 million, or 21%, in the year ended December 31, 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 $3.8 million, or 19%, in the year ended December 31, 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 of Trailblazer on April 1, 2014 as compared to the costs allocated to Trailblazer by TD prior to April 1, 2014. Taxes, other than income taxes, decreased $1.0 million, or 14%, in the year ended December 31, 2014 when compared to the same period in the prior year, primarily due to lower property taxes as a result of successful appeals with state taxing authorities on the assessed value of property. Year Ended December 31, 2013 Compared to the Period from January 1, 2012 to November 12, 2012 Revenues. Natural Gas Transportation & Logistics segment revenues were $127.9 million for the year ended December 31, 2013, compared to $104.0 million for the period from January 1, 2012 to November 12, 2012, which represents a 7% increase in average monthly revenues. The increase in average monthly revenues was primarily driven by a 13% increase in average monthly transportation services revenue during 2013, partially offset by a 48% decrease in average monthly natural gas sales revenue. The increase in average monthly transportation services revenue was primarily due to $21.5 million of transportation services revenue at Trailblazer during the year ended December 31, 2013, partially offset by a decrease in transportation firm contracted capacity and lower throughput volumes at TIGT, primarily from off-system customers. The decrease in average monthly natural gas sales revenue was primarily caused by lower sales volumes as well as a 29% decrease in natural gas sales prices at TIGT, partially offset by $1.4 million of natural gas sales at Trailblazer during the year ended December 31, 2013. Natural gas sales volumes at TIGT decreased due to reduced natural gas recoveries from our customers caused by lower throughput as well as decreased sales of gas inventory during the year ended December 31, 2013. Operating costs and expenses. Operating costs and expenses were $103.8 million for the year ended December 31, 2013 compared to $69.4 million for the period from January 1, 2012 to November 12, 2012, which represents a 30% increase in average monthly operating costs and expenses. Cost of sales and transportation services were $19.3 million for the year ended December 31, 2013 compared to $14.4 million for the period from January 1, 2012 to November 12, 2012, which represents a 17% increase in average monthly cost of sales and transportation services. This increase is primarily due to cost of sales and transportation services of $9.0 million at Trailblazer during the year ended December 31, 2013, partially offset by decreased gas sales and decreased fuel recoveries as a result of lower throughput at TIGT. Operations and maintenance costs were $26.7 million for the year ended December 31, 2013 compared to $21.6 million for the period from January 1, 2012 to November 12, 2012, which represents a 7% increase in average monthly operations and maintenance costs. The increase is primarily driven by $3.5 million of operations and maintenance costs at Trailblazer during the year ended December 31, 2013, partially offset by decreased operating costs at TIGT associated with a section of pipe that was idled in the second quarter of 2013, resulting in the sole shipper under contract for that section not transporting gas in the second half of 2013, and a reduction in integrity maintenance projects at TIGT during 2013 when compared to the period from January 1, 2012 to November 12, 2012. Depreciation and amortization was $30.2 million for the year ended December 31, 2013 compared to $17.9 million for the period from January 1, 2012 to November 12, 2012, which represents a 46% increase in average monthly depreciation and amortization. The increase was primarily driven by $7.3 million of depreciation and amortization at Trailblazer during the year ended December 31, 2013, as well as the higher cost basis of property, plant and equipment as a result of the acquisition of TIGT by TD on November 13, 2012. General and administrative expenses during the year ended December 31, 2013 were $20.6 million compared to $9.0 million for the period from January 1, 2012 to November 12, 2012, which represents a 99% increase in average monthly general and administrative expenses. The increase was due in part to general and administrative costs of $5.6 million at Trailblazer during the year ended December 31, 2013. The remaining increase was largely reflective of TEP Pre-Predecessor Parent’s scale advantage during the 2012 period in supporting similar required administrative functions by a substantially larger number of operated businesses, as well as the addition of general and administrative costs associated with Trailblazer and Pony Express during the year ended December 31, 2013. Taxes, other than income taxes, were $7.1 million for the year ended December 31, 2013 compared to $6.5 million for the period from January 1, 2012 to November 12, 2012, which represents a 6% decrease in average monthly taxes, other than income taxes. The decrease was primarily due to lower property taxes as a result of successful appeals with state taxing authorities on the assessed value of property during 2013, partially offset by $1.1 million of taxes, other than income taxes, recognized at Trailblazer during the year ended December 31, 2013. 63 Year Ended December 31, 2013 Compared to the Period from November 13, 2012 to December 31, 2012 Revenues. Natural Gas Transportation & Logistics segment revenues were $127.9 million for the year ended December 31, 2013, compared to $16.7 million for the period from November 13, 2012 to December 31, 2012, which represents consistent average monthly revenues for the periods. Operating costs and expenses. Operating costs and expenses were $103.8 million for the year ended December 31, 2013 compared to $18.2 million for the period from November 13, 2012 to December 31, 2012, which represents a 25% decrease in average monthly operating costs and expenses. Cost of sales and transportation services were $19.3 million for the year ended December 31, 2013 compared to $2.3 million for the period from November 13, 2012 to December 31, 2012, which represents a 10% increase in average monthly cost of sales and transportation services driven by an increase in natural gas sales. Operations and maintenance costs were $26.7 million for the year ended December 31, 2013 compared to $3.0 million for the period from November 13, 2012 to December 31, 2012, which represents a 15% increase in average monthly operations and maintenance costs. The increase was primarily due to increased integrity maintenance projects, as the majority of planned integrity maintenance projects for 2012 were completed prior to the sale of TIGT to TD in November 2012. Depreciation and amortization was $30.2 million for the year ended December 31, 2013 compared to $4.2 million for the period from November 13, 2012 to December 31, 2012, which represents a 7% decrease in average monthly depreciation and amortization. General and administrative expenses during the year ended December 31, 2013 were $20.6 million compared to $7.3 million for the period from November 13, 2012 to December 31, 2012, which represents a 63% decrease in average monthly general and administrative expenses. The decrease was primarily due to significant legal and other acquisition costs recognized during the 2012 period associated with the acquisition of TIGT, Trailblazer and TMID on November 13, 2012. Taxes, other than income taxes, were $7.1 million for the year ended December 31, 2013 compared to $1.2 million for the period from November 13, 2012 to December 31, 2012, which represents a 25% decrease in average monthly taxes, other than income taxes. The decrease was primarily due to lower property taxes as a result of successful appeals with state taxing authorities on the assessed value of property during 2013. The following provides a summary of our Crude Oil Transportation & Logistics segment results of operations for the periods indicated: Segment Financial Data - Crude Oil Transportation & Logistics Year Ended December 31, 2014 Year Ended December 31, 2013 Period from November 13 to December 31, 2012 Period from January 1 to November 12, 2012 TEP TEP Pre-Predecessor (1) (in thousands) (in thousands) Revenues: Crude Oil transportation services ........................... $ Total revenues ............................................... $ 28,343 28,343 — $ — — $ — Operating costs and expenses: Cost of sales and transportation services ................ Operations and maintenance................................... Depreciation and amortization................................ General and administrative ..................................... Taxes, other than income taxes............................... Total operating costs and expenses ............... Operating income (loss)................................................. $ Segment Adjusted EBITDA........................................... $ 7,025 717 12,067 4,683 250 24,742 3,601 15,711 — — 3,028 128 — — — 378 — — 3,156 (3,156) $ (43) $ $ $ 378 (378) $ — $ — — — — — — — — — — (1) As discussed further in Note 2 – Summary of Significant Accounting Policies to the accompanying consolidated financial statements, financial information for the TEP Pre-Predecessor has not been recast to reflect the operations of Pony Express. 64 Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013 Revenues. Crude Oil Transportation & Logistics segment revenues of $28.3 million for the year ended December 31, 2014 represents transportation revenue on Pony Express, which was placed in service in October 2014. There were no revenues for the year ended December 31, 2013. Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation & Logistics segment were $24.7 million for the year ended December 31, 2014 compared to $3.2 million for the year ended December 31, 2013. Operating costs and expenses for the year ended December 31, 2014 include costs associated with the start of commercial operations in October 2014 as well as the amortization of the Pony Express oil conversion use rights as discussed further in Note 8 – Goodwill and Other Intangible Assets. For the year ended December 31, 2013, operating costs and expenses consisted primarily of the amortization of the Pony Express oil conversion use rights. Year Ended December 31, 2013 Compared to the Period from November 13, 2012 to December 31, 2012 Revenues. There were no Crude Oil Transportation & Logistics segment revenues for the year ended December 31, 2013 or the period from November 13, 2012 to December 31, 2012. Operating costs and expenses. Operating costs and expenses were $3.2 million for the year ended December 31, 2013 compared to $0.4 million for the period from November 13, 2012 to December 31, 2012, which represents a 10% increase in average monthly operating costs and expenses. Operating costs and expenses in the segment for the year ended December 31, 2013 and the period from November 13, 2012 to December 31, 2012 consisted primarily of amortization of the Pony Express oil conversion use rights, as well as general & administrative costs during the year ended December 31, 2013. The following provides a summary of our Processing & Logistics segment results of operations for the periods indicated: Segment Financial Data - Processing & Logistics (1) TEP TEP Pre-Predecessor Year Ended December 31, 2014 Year Ended December 31, 2013 Period from November 13 to December 31, 2012 Period from January 1 to November 12, 2012 (in thousands) (in thousands) Revenues: Natural gas liquids sales ......................................... $ Natural gas sales ..................................................... Processing and other revenues................................ 170,924 $ 146,313 $ 18,554 $ 2,457 35,009 3,481 14,775 1,702 1,716 21,972 Total revenues ............................................... 208,390 164,569 Operating costs and expenses: Cost of sales and transportation services ................ 160,756 128,781 16,834 Operations and maintenance................................... Depreciation and amortization................................ General and administrative ..................................... Taxes, other than income taxes............................... 11,438 11,193 4,073 353 8,722 6,720 3,562 312 Total operating costs and expenses ............... 187,813 148,097 Operating income........................................................... $ Segment Adjusted EBITDA........................................... $ 20,577 33,089 $ $ 16,472 23,192 $ $ 881 823 1,471 42 20,051 1,921 2,744 $ $ 106,355 5,820 4,811 116,986 87,770 8,276 2,752 2,324 314 101,436 15,550 18,302 (1) Segment results as presented represent total revenue and Adjusted EBITDA, including intersegment activity. For reconciliations to the consolidated financial data, see Note 18 – Reporting Segments to the accompanying consolidated financial statements. 65 Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013 Revenues. Processing & Logistics segment revenues were $208.4 million for the year ended December 31, 2014, compared to $164.6 million for the year ended December 31, 2013, which represents a $43.8 million, or 27%, increase in segment revenues. The increase in segment revenues was primarily due to a $24.6 million increase in NGL sales driven by increased volumes processed partially offset by a 7% decrease in average NGL prices, a $20.2 million increase in processing fees driven by the conversion of two significant customers from percent of proceeds or keep whole processing contracts to fee-based processing contracts and revenue of $5.0 million from Water Solutions, which was consolidated in May 2014, partially offset by decreased natural gas sales of $1.0 million due to lower volumes. Operating costs and expenses. Operating costs and expenses in the Processing & Logistics segment were $187.8 million for the year ended December 31, 2014 compared to $148.1 million for the year ended December 31, 2013, which represents an increase of $39.7 million, or 27%. Cost of sales and transportation services increased $32.0 million, or 25%, in the year ended December 31, 2014 when compared to the same period in the prior year, primarily driven by an increase in NGL producer settlements as a result of increased volumes processed under contracts converted to fee based as discussed above and increased volumes processed, partially offset by a 7% decrease in average NGL prices. Operations and maintenance costs increased $2.7 million, or 31%, in the year ended December 31, 2014 when compared to the same period in the prior year, primarily driven by $1.3 million of costs attributable to Water Solutions, which was consolidated in May 2014, increased environmental reserves recorded in 2014, and increased costs associated with testing and treatment resulting from high water content of gas processed during the period. Depreciation and amortization increased $4.5 million, or 67%, in the year ended December 31, 2014 when compared to the same period in the prior year, primarily driven by depreciation and amortization of $3.3 million from the Water Solutions fixed and intangible assets consolidated in May 2014 and $1.1 million from asset additions as a result of expansion activities at TMID that were substantially completed in the third quarter of 2013. General and administrative costs increased $0.5 million, or 14%, in the year ended December 31, 2014 when compared to the same period in the prior year, primarily driven by costs associated with Water Solutions, which was consolidated in May 2014. Taxes, other than income taxes, were comparable during the year ended December 31, 2014 and the same period in the prior year. Year Ended December 31, 2013 Compared to the Period from January 1, 2012 to November 12, 2012 Revenues. Processing & Logistics segment revenues were $164.6 million for the year ended December 31, 2013, compared to $117.0 million for the period from January 1, 2012 to November 12, 2012, which represents a 22% increase in average monthly revenues primarily attributable to increased average monthly NGL sales due to an increase in average monthly volumes of natural gas processed during the year ended December 31, 2013 compared to the 2012 period as a result of new contracts, and an increase in average monthly processing fees of 167% resulting from new and revised fee-based contracts that were not in effect during the 2012 period. Increases were partially offset by a decrease in natural gas sales due to sales of residue gas purchased from a customer during the 2012 period that did not occur during the 2013 period and natural gas purchase and sales transactions in 2012 to redirect processed dry gas around the Casper plant in order to optimize plant capacity and efficiency. Operating costs and expenses. Operating costs and expenses were $148.1 million for the year ended December 31, 2013 compared to $101.4 million for the period from January 1, 2012 to November 12, 2012, which represents a 27% increase in average monthly operating costs and expenses. Cost of sales and transportation services were $128.8 million for the year ended December 31, 2013 compared to $87.8 million for the period from January 1, 2012 to November 12, 2012, which represents a 27% increase in average monthly cost of sales and transportation services due to increased volumes during 2013 due to new or revised fee-based contracts, partially offset by the purchase of residue gas from a customer in 2012 and gas purchases related to the natural gas purchase and sales transactions in 2012 (both discussed above). Operations and maintenance costs were $8.7 million for the year ended December 31, 2013 compared to $8.3 million for the period from January 1, 2012 to November 12, 2012, which represents a 8% decrease in average monthly operations and maintenance costs. 66 Depreciation and amortization was $6.7 million for the year ended December 31, 2013 compared to $2.8 million for the period from January 1, 2012 to November 12, 2012, which represents a 112% increase in average monthly depreciation and amortization due to the higher cost basis of property, plant and equipment as a result of the acquisition of TMID by TD on November 13, 2012. General and administrative expenses during the year ended December 31, 2013 were $3.6 million compared to $2.3 million for the period from January 1, 2012 to November 12, 2012, which represents a 33% increase in average monthly general and administrative expenses. The increase was largely reflective of TEP Pre-Predecessor Parent’s scale advantage during the 2012 period in supporting similar required administrative functions by a substantially larger number of operated businesses. Taxes, other than income taxes, were $0.3 million for the year ended December 31, 2013 compared to $0.3 million for the period from January 1, 2012 to November 12, 2012, which represents a 13% decrease in average monthly taxes, other than income taxes. The decrease was primarily due to lower property taxes as a result of successful appeals with state taxing authorities on the assessed value of property during 2013. Year Ended December 31, 2013 Compared to the Period from November 13, 2012 to December 31, 2012 Revenues. Processing & Logistics segment revenues were $164.6 million for the year ended December 31, 2013, compared to $22.0 million for the period from November 13, 2012 to December 31, 2012, which represents a 2% decrease in average monthly revenue. The decrease in revenues was primarily attributable to lower natural gas sales revenue due to sales of residue gas purchased from a customer during the 2012 period which did not occur in 2013, partially offset by increased average monthly NGL sales due to an increase in average monthly volumes of NGLs processed during the year ended December 31, 2013 as a result of new contracts. Operating costs and expenses. Operating costs and expenses were $148.1 million for the year ended December 31, 2013 compared to $20.1 million for the period from November 13, 2012 to December 31, 2012, which represents a 3% decrease in average monthly operating costs and expenses. Cost of sales and transportation services were $128.8 million for the year ended December 31, 2013 compared to $16.8 million for the period from November 13, 2012 to December 31, 2012, which represents a 1% increase in average monthly cost of sales and transportation services. Operations and maintenance costs were $8.7 million for the year ended December 31, 2013 compared to $0.9 million for the period from November 13, 2012 to December 31, 2012, which represents a 30% increase in average monthly operations and maintenance costs. The increase was primarily due to maintenance projects during the Casper and Douglas plant turnarounds in the third quarter of 2013. There were no plant turnarounds during the period from November 13, 2012 to December 31, 2012. Depreciation and amortization was $6.7 million for the year ended December 31, 2013 compared to $0.8 million for the period from November 13, 2012 to December 31, 2012, which represents a 7% increase in average monthly depreciation and amortization. General and administrative expenses during the year ended December 31, 2013 were $3.6 million compared to $1.5 million for the period from November 13, 2012 to December 31, 2012, which represents a 68% decrease in average monthly general and administrative expenses. The decrease was primarily due to significant legal and other acquisition costs recognized during the 2012 period associated with the acquisition of TIGT and TMID on November 13, 2012. Taxes, other than income taxes, were $0.3 million for the year ended December 31, 2013 compared to $42,000 for the period from November 13, 2012 to December 31, 2012, which represents a 4% decrease in average monthly taxes, other than income taxes. Liquidity and Capital Resources Overview Our primary sources of liquidity for the year ended December 31, 2014 were proceeds from the issuance of common units, 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/or debt securities. We believe that cash on hand, cash generated from operations and availability under our revolving credit facility will be adequate to meet our operating needs, our planned short-term capital and debt service requirements and our planned cash distributions to unitholders. We believe that future internal growth projects or potential acquisitions will be funded primarily through a combination of borrowings under our revolving credit facility and issuances of debt and/or equity securities. 67 Our total liquidity as of December 31, 2014 and 2013 was as follows: December 31, 2014 December 31, 2013 Cash on hand ................................................................................................................ $ Total capacity under the revolving credit facility ................................................. Less: Outstanding borrowings under the revolving credit facility................. Less: Letters of credit issued under the revolving credit facility................... Available capacity under the revolving credit facility .......................................... Total liquidity............................................................................................................... $ Revolving Credit Facility $ (in thousands) 867 850,000 (559,000) — 291,000 291,867 $ — 500,000 (135,000) (654) 364,346 364,346 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. The Amendment modified 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 from $40 million to $60 million, (iii) increase the sublimit for letters of credit from $50 million 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 revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict TEP’s ability (as well as the ability of TEP’s restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions (including distributions from available cash, if a default or event of default under the credit agreement then exists or would result from making such a distribution), change the nature of TEP’s business, engage in certain mergers or make certain investments and acquisitions, enter into non-arms-length transactions with affiliates and designate certain subsidiaries as "Unrestricted Subsidiaries." In addition, TEP is required to maintain a consolidated leverage ratio of not more than 4.75 to 1.00 (which will be increased to 5.25 to 1.00 for certain measurement periods following the consummation of certain acquisitions) and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of December 31, 2014, TEP is in compliance with the covenants required under the revolving credit facility. The unused portion of the revolving credit facility is subject to a commitment fee, which 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 December 31, 2014, the weighted average interest rate on outstanding borrowings was 2.45%. July 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 $319.3 million after deducting the underwriter's discount and offering expenses paid by TEP. TEP used the net proceeds from the offering to fund a portion of the consideration for the acquisition of a 33.3% membership interest in Pony Express. Equity Distribution Agreement On October 31, 2014, we entered into an equity distribution agreement pursuant to which we may sell from time to time through a group of managers, as our sales agents, common units representing limited partner interests having an aggregate offering price of up to $200 million. Sales of the common units, if any, will be made by means of ordinary brokers’ transactions, to or through a market maker or directly on or through an electronic communication network, a "dark pool" or any similar market venue, or as otherwise agreed by the Partnership and one or more of the managers. We intend to use the net proceeds from any sale of the units for general partnership purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt. As of December 31, 2014, TEP had issued and sold 28,625 common units with a weighted average sales price of $44.20 per unit under our equity distribution agreement for net proceeds of approximately $1.1 million (net of approximately $215,000 in commissions and professional service expenses). We used the net proceeds for general partnership purposes. At December 31, 2014, approximately $198.7 million in aggregate offering price remained available to be issued and sold under the equity distribution agreement. 68 Working Capital Working capital is the amount by which current assets exceed current liabilities. As of December 31, 2014, we had a working capital surplus of $35.7 million compared to a working capital deficit of $127.0 million at December 31, 2013, which represents an increase in working capital of $162.8 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, payments to suppliers, and receivables from related parties, 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 increase in working capital from December 31, 2013 to December 31, 2014 was primarily attributable to a decrease of $87.1 million in accounts payable driven by a decrease in construction accruals at Pony Express, an increase of $73.4 million in receivables from related parties resulting from the Pony Express cash balance swept to TD under the cash management agreement, and an increase of $9.7 million in trade receivables primarily due to Pony Express commencing commercial operations in 2014. A material adverse change in operations. available financing under our revolving credit facility, or available financing from the equity or debt capital markets could impact our ability to fund our requirements for liquidity and capital resources in the future. Cash Flows The following table and discussion presents a summary of our cash flow for the periods indicated: TEP Year Ended December 31, 2014 Year Ended December 31, 2013 Period from November 13 to December 31, 2012 (in thousands) TEP Pre-Predecessor (1) Period from January 1 to November 12, 2012 (in thousands) Net cash provided by (used in): Operating activities .................................... $ Investing activities...................................... $ Financing activities .................................... $ $ 79,444 (1,102,729) $ $ 1,024,152 $ 82,482 (347,610) $ $ 265,128 10,464 (12,754) 308 $ $ $ 81,335 (21,692) (57,661) (1) As discussed further in Note 2 – Summary of Significant Accounting Policies to the accompanying consolidated financial statements, financial information for the TEP Pre-Predecessor has not been recast to reflect the operations of Trailblazer and Pony Express. Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013 Operating Activities. Cash flows provided by operating activities were $79.4 million and $82.5 million for the years ended December 31, 2014 and 2013, respectively. The decrease in net cash flows provided by operating activities of $3.0 million was primarily driven by the increase in net cash outflows for changes in working capital, primarily due to the timing of payments and a decrease in producer settlements at TMID as a result of lower NGL prices, partially offset by the increase in operating results in the year ended December 31, 2014 compared to the year ended December 31, 2013. Investing Activities. Cash flows used in investing activities were $1.1 billion and $347.6 million for the years ended December 31, 2014 and 2013, respectively. During the year ended December 31, 2014, net cash used in investing activities were driven by capital expenditures of $665.7 million, primarily due to construction of the Pony Express System, including the lateral in Northeast Colorado, as well as the capacity expansion projects at TMID and other expansion projects at Trailblazer, cash outflows of $270.0 million associated with the related party loan to TD under the Pony Express cash management agreement, and cash outflows of $150.0 million, $7.6 million, and $27.0 million for the acquisitions of Trailblazer, Water Solutions and Pony Express, respectively. These cash outflows were partially offset by cash inflows of $20 million from the return of funds deposited with Shell in support of the crude oil resale obligation of Pony Express. In the year ended December 31, 2013, net cash used in investing activities was driven by $346.0 million in capital expenditures, consisting primarily of spending on the conversion and construction of the Pony Express System and capacity expansion and efficiency upgrade projects at TMID, and to a lesser extent, capital expenditures at TIGT. 69 Financing Activities. Cash flows provided by financing activities were $1.0 billion and $265.1 million for the years ended December 31, 2014 and 2013, respectively. Financing cash inflows for the year ended December 31, 2014 were primarily driven by the proceeds from net borrowings under the revolving credit facility of $424.0 million, net proceeds of $320.4 million from the issuance of 8,050,000 common units in a public offering which closed on July 25, 2014 and units issued under the ATM program in the fourth quarter of 2014, net contributions from Predecessor Member of $312.1 million, and 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. These cash inflows were partially offset by distributions to TEP unitholders of $68.1 million. Cash flows provided by financing activities for the year ended December 31, 2013 consisted primarily of net contributions from Predecessor Member of $379.9 million, net cash inflows of $290.5 million from the completion of our IPO on May 17, 2013, and net borrowings under our revolving credit facility of $135.0 million. These cash inflows were partially offset by the repayment of $400.0 million of debt assumed from TD, net distributions to TD of $118.5 million prior to the closing of our IPO on May 17, 2013, and distributions to unitholders of $18.2 million. Year Ended December 31, 2013 Compared to the Period from January 1, 2012 to November 12, 2012 and the Period from November 13, 2012 to December 31, 2012 Operating Activities. Cash flows provided by operating activities were $82.5 million for the year ended December 31, 2013, compared to cash flows provided of $81.3 million and $10.5 million for the period January 1, 2012 through November 12, 2012 and the period November 13, 2012 through December 31, 2012, respectively. The decrease in cash flows provided by operating activities is primarily driven by decreased operating results during the year ended December 31, 2013, partially offset by an increase in net cash flows from changes in working capital. Investing Activities. Cash flows used in investing activities were $347.6 million for the year ended December 31, 2013, compared to cash flows used in investing activities of $21.7 million and $12.8 million for the period January 1, 2012 through November 12, 2012 and the period November 13, 2012 through December 31, 2012, respectively. Cash flows used in investing activities for the year ended December 31, 2013 consisted primarily of capital expenditures of $346.0 million as discussed above. For the year ended December 31, 2012, expansion capital projects were approximately $23.1 million. Approximately $9.8 million of this amount was incurred for initial engineering, permitting, hydraulic studies and right-of way acquisitions for Pony Express and was settled pursuant to the centralized cash management program in place at the time. In the Midstream segment, we spent approximately $7.5 million to increase the capacity and efficiency of our Douglas processing plant in order to accommodate our customers’ increasing natural gas production in the region. In addition, we settled and paid a dispute related to the construction of West Frenchie Draw treating plant in the amount of $5.9 million. Financing Activities. Cash flows provided by financing activities were $265.1 million for the year ended December 31, 2013, compared to cash flows provided by financing activities of $308,000 and cash flows used in financing activities of $57.7 million for the period January 1, 2012 through November 12, 2012 and the period November 13, 2012 through December 31, 2012, respectively. Cash flows provided by financing activities of $265.1 million for the year ended December 31, 2013 were primarily driven by contributions from Predecessor Member, proceeds from our initial public offering, and net borrowings under our revolving credit facility, partially offset by the repayment of debt assumed from TD, net distributions to TD prior to the closing of our IPO on May 17, 2013, and distributions to unitholders as discussed above. Cash flows used in financing activities of $57.7 million for the period from January 1, 2012 to November 12, 2012 represent net distributions to TD. Distributions We intend to pay quarterly distributions at or above the amount of the MQD, which is $0.2875 per unit. As of February 19, 2015, we had a total of 49,868,496 common and general partner units outstanding, which equates to an aggregate MQD of approximately $14.3 million per quarter and approximately $57.3 million per year. We do not have a legal obligation to pay distributions except as provided in our partnership agreement. 70 The following table shows the distributions for the years ended December 31, 2014 and 2013: Distributions General Partner Three Months Ended Date Paid December 31, 2014........ February 13, 2015.......... September 30, 2014 ....... November 14, 2014 ....... June 30, 2014................. August 14, 2014 ............ March 31, 2014.............. May 14, 2014................. December 31, 2013........ February 12, 2014.......... September 30, 2013 ....... November 13, 2013 ....... June 30, 2013................. August 13, 2013 ............ March 31, 2013.............. N/A ................................ Limited Partner Units Incentive Distribution Rights General Partner Units Total Distributions per Limited Partner Unit (in thousands, except per unit amounts) $ 23,782 $ 4,039 $ 20,092 18,596 13,288 12,757 12,049 5,759 N/A 1,208 758 126 63 — — N/A 473 363 330 274 262 245 118 N/A $ 28,294 $ 21,663 19,684 13,688 13,082 12,294 5,877 N/A 0.4850 0.4100 0.3800 0.3250 0.3150 0.2975 0.1422 N/A (1) (1) 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 and June 30, 2013. Capital Requirements The midstream energy business can be capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to consist of the following: • maintenance capital expenditures, which are cash expenditures incurred (including expenditures for the construction or development of new capital assets) that we expect to maintain our long-term operating income or operating capacity. These expenditures typically include certain system integrity, compliance and safety improvements; and • expansion capital expenditures, which are cash expenditures to increase our operating income or operating capacity over the long term. Expansion capital expenditures include acquisitions or capital improvements (such as additions to or improvements on the capital assets owned, or acquisition or construction of new capital assets). We expect to incur approximately $185 million for capital expenditures in 2015, of which approximately $135 million is expected for the construction of the lateral to the Pony Express System located in Northeast Colorado and remaining costs associated with completion of the construction of the Pony Express System, approximately $37 million is expected for other expansion projects, and approximately $13 million is expected for maintenance capital expenditures. The determination of capital expenditures as maintenance or expansion is made at the individual asset level during our budgeting process and as we approve, execute, and monitor our capital spending. The following table summarizes the maintenance and expansion capital expenditures incurred at our consolidated entities: TEP TEP Pre-Predecessor Year Ended December 31, 2014 Year Ended December 31, 2013 Period from November 13, 2012 to December 31, 2012 Period from January 1, 2012 to November 12, 2012 (in thousands) Maintenance capital expenditures............... $ Expansion capital expenditures .................. Total capital expenditures incurred...... $ 9,913 762,073 771,986 $ $ 15,951 422,981 438,932 $ $ 5,562 9,608 15,170 $ $ 6,218 13,322 19,540 71 The decrease in maintenance capital expenditures to $9.9 million for the year ended December 31, 2014 from $16.0 million for the year ended December 31, 2013 is primarily driven by a decrease in maintenance capital expenditures in the Gas Transportation & Logistics segment due to certain compressor and pipeline integrity projects in the Gas Transportation & Logistics segment during the year ended December 31, 2013. Maintenance capital expenditures on our assets occur on a regular schedule, but most major maintenance projects are not required every year so the level of maintenance capital expenditures naturally varies from year to year and varies from quarter to quarter. The increase in expansion capital expenditures to $762.1 million for the year ended December 31, 2014 from $423.0 million for the year ended December 31, 2013 is primarily driven by increased expenditures associated with the conversion and construction of the Pony Express System, which was placed in commercial service in October 2014, and the lateral on the Pony Express System located in Northeast Colorado, which is expected to be placed into commercial service during the first half of 2015. The increase in maintenance capital expenditures to $16.0 million for the year ended December 31, 2013 from $5.6 million and $6.2 million for the periods from November 13, 2012 to December 31, 2012 and January 1, 2012 to November 12, 2012, respectively, is primarily driven by variability in the timing of planned maintenance activities as discussed above. The increase in expansion capital expenditures to $423.0 million for the year ended December 31, 2013 from $9.6 million and $13.3 million for the periods from November 13, 2012 to December 31, 2012 and January 1, 2012 to November 12, 2012, respectively, is primarily driven by expenditures associated with the Pony Express System and lateral in Northeast Colorado as discussed above, and to a lesser extent, capacity expansion and efficiency upgrade projects at TMID, which were substantially completed in the third quarter of 2013. In addition, we invested cash in unconsolidated affiliates of $2.0 million and $1.3 million during the years ended December 31, 2014 and 2013, respectively, to fund our share of capital expansion projects. There were no investments in unconsolidated affiliates during the periods from November 13, 2012 to December 31, 2012 or January 1, 2012 to November 12, 2012. We intend to make cash distributions to our unitholders and our general partner. Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. We expect to fund future capital expenditures with funds generated from our operations, borrowings under our Credit Agreement, the issuance of additional partnership units and/or the issuance of long-term debt. If these sources are not sufficient, we may reduce our discretionary spending. Contractual Obligations Following is a summary of our contractual cash obligations in future periods, representing amounts that were fixed and determinable as of December 31, 2014: Contractual Obligations Payments Due By Period Total Less Than 1 Year 1-3 Years 3-5 Years (in thousands) More Than 5 Years Debt obligations (1) .................................................... Interest on debt obligations (2) ................................... Operating lease and service contract obligations (3).. Land site lease and right-of-way (4)........................... Other purchase commitments (5)................................ Total $ 559,000 $ — $ — $ 559,000 $ 46,113 644,456 889 65,474 13,673 24,439 101 65,439 27,346 55,859 194 35 5,094 57,745 174 — — — 506,413 420 — $1,315,932 $ 103,652 $ 83,434 $ 622,013 $ 506,833 (1) Debt obligations at December 31, 2014 consisted of borrowings under the revolving credit facility. For additional information, see Note 10 - Long-term Debt to the Consolidated Financial Statements in Item 8.—Financial Statements and Supplementary Data. (2) Interest on debt obligations is estimated using current borrowings and interest rates as of December 31, 2014. For additional information, see Note 10 - Long-term Debt to the Consolidated Financial Statements in Item 8.—Financial Statements and Supplementary Data. (3) Operating leases and service contracts consist of leases for crude oil storage as well as office space and equipment. For additional information, see Note 12 - Commitments & Contingent Liabilities to the Consolidated Financial Statements in Item 8.—Financial Statements and Supplementary Data. 72 (4) Land site lease and right-of-way contracts consist of payments to landowners, primarily in our Natural Gas Transportation & Logistics and Crude Oil Transportation & Logistics segments. For additional information, see Note 12 - Commitments & Contingent Liabilities to the Consolidated Financial Statements in Item 8.—Financial Statements and Supplementary Data. (5) Other purchase commitments primarily relate to planned non-reimbursable capital expenditures. 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. In addition to these costs, TEP pays a quarterly reimbursement to TD for costs associated with being a public company. For the calendar year 2015, TEP’s annual cost reimbursements to TD for costs discussed above are expected to be $24.0 million. In addition, annual cost reimbursements from Pony Express to TD are expected to be $20.6 million before noncontrolling interests. The quarterly public company reimbursement is expected to be $625,000 in 2015. However, these reimbursement amounts will be periodically reviewed and adjusted as necessary to continue to reflect reasonable allocation of costs to TEP. These reimbursements are not included in the contractual obligations table above. Off-Balance Sheet Arrangements We do not have any off-balance sheet arrangements. Critical Accounting Policies and Estimates Our significant accounting policies are described in Note 2 - Summary of Significant Accounting Policies to the consolidated financial statements included in Item 8 of this Annual Report. Management’s discussion and analysis of financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosure of contingent assets and liabilities. The accounting policies discussed below are considered by management to be critical to an understanding of our financial statements as their application places the most significant demands on management’s judgment. Due to the inherent uncertainties involved with this type of judgment, actual results could differ significantly from estimates and may have a material adverse impact on our results of operations, equity or cash flows. For additional information concerning our other accounting policies, please read the notes to the financial statements included in this report. Revenue Recognition We recognize revenues when services are rendered or goods are sold to a purchaser at a fixed and determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. Natural gas liquids sales occur in the Processing & Logistics segment and consist of the sale of outputs from our processing plants and the marketing of natural gas liquids that are delivered by our suppliers under either fee-based arrangements or percent-of-proceeds arrangements. Under these arrangements, we treat and process the natural gas delivered by our suppliers, and then sell the resulting NGLs and condensate based on published index market prices. We remit to the producers an agreed-upon percentage of the actual proceeds that we receive from our sales of the NGLs and condensate. We keep the difference between the proceeds received and the amount remitted back to the producer. We generally report revenues gross in the consolidated statements of income, as we typically act as the principal in these transactions, take custody to the product, and incur the risks and rewards of ownership. Processing and other revenues primarily represent processing fees for processing, treating and fractionation of natural gas earned under fee-based arrangements and revenue from water services earned in the Processing & Logistics segment. Natural gas sales occur in both the Natural Gas Transportation & Logistics segment and in the Processing & Logistics segment. In the Natural Gas Transportation & Logistics segment, transportation services revenue is recognized when a portion of the natural gas transported by customers is collected as a contractual fee to compensate TEP and TEP Pre-Predecessor for fuel consumed by pipeline and storage operations. We take title and record revenue at market prices when the volumes included in the contractual fee are delivered from the customer and injected into our storage facility. When the excess volumes are eventually sold we record natural gas sales revenue at the contractual sales price and cost of sales and transportation services at average cost. In addition, when operational conditions allow, TEP and TEP Pre-Predecessor occasionally sell "base gas," which refers to the minimum volume of natural gas required in order to operate the storage facility. In the Processing & Logistics 73 segment, we purchase natural gas primarily for use in our operations and for meeting contractual requirements to deliver natural gas to certain customers. In addition, some of our contractual arrangements allow us to keep a portion of the processed natural gas as compensation for processing services. We generate revenue by selling the volumes of natural gas received or purchased that exceed our business needs. Natural gas transportation services occur in the Natural Gas Transportation & Logistics segment. In many cases (generally described as "firm service"), the customer pays a two-part rate that includes (i) a fee reserving the right to transport or store natural gas in TEP and TEP Pre-Predecessors’ facilities and (ii) a per-unit rate for volumes actually transported or injected into/ withdrawn from storage. The fee-based component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/withdrawn from TEP and TEP Pre-Predecessors’ storage facilities. In other cases (generally described as "interruptible service"), there is no fee associated with the services because the customer accepts the possibility that service may be interrupted at TEP and TEP Pre-Predecessors’ discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements. In addition to "firm" and "interruptible" transportation services, TEP and TEP Pre-Predecessor also provide natural gas park and loan services to assist customers in managing short- term gas surpluses or deficits. Revenues are recognized as services are provided, based on the terms negotiated under these contracts. Crude oil transportation services occur in the Crude Oil Transportation & Logistics segment. TEP provides various types of crude oil transportation services to its customers and, other than pipeline allowance oil, does not take title to the crude oil and does not incur the risks and rewards of ownership. In many cases the customer has committed to ship a fixed quantity of oil barrels per month. For barrels physically received by TEP and delivered to the customers’ agreed upon destination point, revenue is recognized in the period the service is provided. Shipper deficiencies, or barrels committed by the customer to be transported in a month but not physically received by TEP for transport or delivered to the customers’ agreed upon destination point are charged at the committed tariff rate per barrel and recorded as a deferred liability until the barrels are physically transported and delivered by TEP. In the case of non-committed shippers, revenue is recognized in the same manner utilized for the barrels physically transported and delivered. A loss allowance is factored into the crude oil tariffs to offset losses in transit. As crude oil is transported, TEP earns oil for its services as pipeline allowance oil. Any pipeline allowance oil that remains after replacing losses in transit can be sold. We take title and record revenue at market prices when the volumes included in the pipeline loss allowance are delivered from the customer. When pipeline loss allowance oil is eventually sold we record revenue at the contractual sales price and cost of sales and transportation services at average cost as discussed in "Inventories" in Note 2 - Summary of Significant Accounting Policies. There were no sales of pipeline allowance oil during the year ended December 31, 2014. Accounting for Regulatory Activities Our regulated activities are accounted for in accordance with the "Regulated Operations" topic of the Financial Accounting Standards Board Accounting Standard Codification, which we refer to as the Codification. The Regulated Operations topic prescribes the circumstances in which the application of GAAP is affected by the economic effects of regulation. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. Property, Plant and Equipment Property, plant and equipment is stated at historical cost, which for constructed plants includes indirect costs such as payroll taxes, other employee benefits, allowance for funds used during construction for regulated assets and other costs directly related to the projects. Expenditures that increase capacities, improve efficiencies or extend useful lives are capitalized. Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of the regulated depreciable utility property, plant and equipment, plus the cost of removal less salvage value, is recorded in accumulated depreciation with no effect on current period earnings. Gains or losses are recognized upon retirement of utility property, plant and equipment constituting an operating unit or system, and land, when sold or abandoned. We review our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss results when the estimated undiscounted future net cash flows expected to result from the asset’s use and its eventual disposition are less than its carrying amount. Commitments and Contingencies We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss. 74 Environmental Costs TEP and TEP Pre-Predecessor expense or capitalize, as appropriate, environmental expenditures that relate to current operations. TEP and TEP Pre-Predecessor expense amounts that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation. TEP and TEP Pre-Predecessor do not discount environmental liabilities to a net present value, and record environmental liabilities when environmental assessments and/or remedial efforts are probable and costs can be reasonably estimated. Recording of these accruals coincides with the completion of a feasibility study or a commitment to a formal plan of action. Estimates of environmental liabilities are based on currently available facts and presently enacted laws and regulations taking into consideration the likely effects of other factors including our prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual cost or new information. Risk Management Activities We may enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our natural gas purchases and sales in our Natural Gas Transportation and Logistics segment, which expose us to risks associated with changes in the market price of natural gas. Specifically, these risks are associated with (i) pre-existing or anticipated physical natural gas sales, (ii) natural gas purchases; and (iii) natural gas system use and storage. During the period from January 1, 2012 to November 12, 2012, we recognized no gain or loss as a result of ineffectiveness of these hedges. We did not exclude any component of the derivative contracts’ gain or loss from the assessment of hedge effectiveness. As the hedged sales and purchases took place and we recorded them into earnings, we also reclassified the associated gains and losses included in accumulated other comprehensive income into earnings. Subsequent to November 13, 2012, we discontinued the use of hedge accounting and began recording the changes in fair value of our derivative contracts in current earnings. We do not currently hedge the commodity exposure in our processing contracts with respect to our natural gas and NGL purchases and sales in our Processing & Logistics segment. However, we monitor the mix of our contractual arrangements described above and have a minimal amount of exposure to natural gas and NGL price volatility in our current contract portfolio. Goodwill We evaluate goodwill for impairment annually in the third quarter, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We evaluate goodwill impairment by reporting unit level, which is an operating segment as defined in the segment reporting guidance of the Codification, using either the qualitative assessment option or the two-step test approach depending on facts and circumstances of the reporting unit. Our reporting units are the same as our reporting segments. If we, after performing the qualitative assessment, determine it is "more likely than not" that the fair value of a reporting unit is greater than its carrying amount, the two-step impairment test is unnecessary. When goodwill is evaluated for impairment using the two- step test, the carrying amount of the reporting unit is compared to its fair value in Step 1 and if the fair value exceeds the carrying amount, Step 2 is unnecessary. If the carrying amount exceeds the reporting unit’s fair value, this could indicate potential impairment and Step 2 of the goodwill evaluation process is required to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any. When Step 2 is necessary, the fair value of individual assets and liabilities is determined using valuations, or other observable sources of fair value, as appropriate. If the carrying amount of goodwill exceeds its implied fair value, the excess is recognized as an impairment loss. We completed our impairment testing of goodwill in the third quarter of 2014 using the methodology described herein, and determined there was no impairment. Equity-Based Compensation Equity-based compensation grants are measured at their grant date fair value and related compensation cost is recognized over the vesting period of the grant. Compensation cost for awards with graded vesting provisions is recognized on a straight- line basis over the requisite service period of each separately vesting portion of the award. Estimating the fair value of each award, the number of awards that will ultimately vest, and the forfeiture rate requires management to apply judgment to estimate the tenure of our employees and the achievement of certain performance targets over the performance period. If actual results are not consistent with our assumptions and judgments or our assumptions and estimates change due to new information, we may experience material changes in compensation expense. 75 Emerging Growth Company We are an "emerging growth company" pursuant to the JOBS Act. The JOBS Act provides that an emerging growth company may delay adopting new or revised accounting standards until such time as those standards apply to private companies. We have elected to take advantage of this exemption and, therefore, may adopt new or revised accounting standards at the time those standards apply to private companies. As a result of our election to take advantage of this transition period, our financial statements may not be comparable to those of companies that comply with public company effective dates for the adoption of new or revised accounting standards. This election had no material impact on the consolidated financial statements included in this Annual Report. Item 7A. 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 December 31, 2014 approximately 87% of our reserved processing capacity was subject to fee-based processing contracts, with the remaining 13% subject to percent of proceeds or keep whole processing contracts, a notable shift toward fee-based processing contracts as compared to approximately 66% fee-based contracts and approximately 34% of percent of proceeds or keep whole processing 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 & Logistics segment comprised approximately 30% of our Adjusted EBITDA for the years ended December 31, 2014 and 2013. We have a limited amount of direct commodity price exposure related to crude oil collected as part of our contractual pipeline loss allowance at Pony Express. We do not currently hedge this commodity exposure. We also have a limited amount of direct commodity price exposure related to natural gas collected related to electrical compression costs and lost and unaccounted for gas on the TIGT System. Historically, we have entered into derivative contracts with third parties for a substantial majority of the gas we expect to collect during the current year for the purpose of hedging our commodity price exposures. We expect to continue these hedging activities for the foreseeable future. As of December 31, 2014, we had no natural gas hedges outstanding. 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. As of December 31, 2014 we had no natural gas hedges outstanding and thus no fair value change due to a hypothetical increase in the natural gas price forward curve. 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. 76 Interest Rate Risk As described in "Liquidity and Capital Resources Overview" above, we currently have an $850 million revolving credit facility. Borrowings under the revolving credit facility will bear interest, at our option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar Rate, plus, in each case, an applicable margin. For loans bearing interest based on the base rate, the applicable margin was initially 1.00%, and for loans bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin was initially 2.00%. After June 25, 2014, the applicable margin ranges from 0.75% to 2.75%, based upon our total leverage ratio and whether we have elected the base rate or the reserve adjusted Eurodollar rate. 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 December 31, 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, guarantees or bonds as forms of credit support. We have historically experienced only minimal credit losses in connection with our receivables. A substantial majority of our revenue is produced under long-term, firm, fee-based contracts with high-quality customers. The customer base we currently serve under these contracts generally has a strong credit profile, with over 70% of our revenues derived from customers with investment grade credit ratings as of December 31, 2014. 77 Item 8. Financial Statements and Supplementary Data Report of Independent Registered Public Accounting Firm To the Partners of Tallgrass Energy Partners, LP: In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, partners’ capital and cash flows present fairly, in all material respects, the financial position of Tallgrass Energy Partners, LP and its subsidiaries (the "Partnership") at December 31, 2014 and 2013, and the results of their operations and their cash flows for the years ended December 31, 2014 and 2013, and for the period from November 13, 2012 to December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. /s/ PricewaterhouseCoopers LLP Denver, Colorado February 19, 2015 78 Report of Independent Registered Public Accounting Firm To the Partners of Tallgrass Energy Partners, LP: In our opinion, the accompanying statement of income, comprehensive income, partners’ capital and cash flows present fairly, in all material respects, Tallgrass Energy Partners Pre-Predecessor’s ("TEP Pre-Predecessor") results of operations and their cash flows for the period from January 1, 2012 to November 12, 2012 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the TEP Pre-Predecessor management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. /s/ PricewaterhouseCoopers LLP Denver, Colorado March 18, 2013 79 TALLGRASS ENERGY PARTNERS, LP CONSOLIDATED BALANCE SHEETS December 31, 2014 December 31, 2013 (in thousands) Current Assets: ASSETS Cash and cash equivalents .................................................................................................. $ Accounts receivable, net ..................................................................................................... Receivable from related party............................................................................................. Gas imbalances ................................................................................................................... Inventories .......................................................................................................................... Prepayments and other current assets ................................................................................. Total Current Assets.................................................................................................... Property, plant and equipment, net ............................................................................................. Goodwill ..................................................................................................................................... Intangible asset, net..................................................................................................................... Deferred financing costs ............................................................................................................. Deferred charges and other assets............................................................................................... Total Assets................................................................................................................................. $ LIABILITIES AND PARTNERS’ EQUITY Current Liabilities: Accounts payable, including $45,534 and $89,212 related to variable interest entities..... $ Accounts payable to related parties .................................................................................... Gas imbalances ................................................................................................................... Derivative liabilities at fair value........................................................................................ Accrued taxes...................................................................................................................... Accrued liabilities ............................................................................................................... Deferred revenue................................................................................................................. Other current liabilities ....................................................................................................... Total Current Liabilities.............................................................................................. Long-term debt ........................................................................................................................... Other long-term liabilities and deferred credits.......................................................................... Total Long-term Liabilities......................................................................................... Commitments and Contingencies Equity: Predecessor Equity.............................................................................................................. Common unitholders (32,834,105 and 24,300,000 units issued and outstanding at December 31, 2014 and 2013, respectively)....................................................................... Subordinated unitholder (16,200,000 units issued and outstanding at December 31, 2014 and 2013) ................................................................................................................... General partner (834,391 and 826,531 units issued and outstanding at December 31, 2014 and 2013, respectively) .............................................................................................. Total Partners’ Equity................................................................................................. Noncontrolling interests...................................................................................................... $ Total Equity................................................................................................................. $ Total Liabilities and Equity......................................................................................................... $ 867 $ 39,768 73,393 2,442 13,045 2,766 132,281 1,853,081 343,288 104,538 5,528 18,481 — 30,033 — 3,128 5,549 16,986 55,696 1,116,806 334,715 102,567 4,512 17,117 2,457,197 $ 1,631,413 62,329 $ 149,452 3,915 3,611 — 3,989 9,384 5,468 7,872 96,568 559,000 6,478 565,478 — 800,333 274,133 (35,743) 1,038,723 756,428 1,795,151 2,457,197 $ $ $ 7,137 3,664 184 5,520 5,550 538 10,695 182,740 135,000 4,572 139,572 247,221 455,197 274,666 14,078 991,162 317,939 1,309,101 1,631,413 The accompanying notes are an integral part of these consolidated financial statements. 80 TALLGRASS ENERGY PARTNERS, LP CONSOLIDATED STATEMENTS OF INCOME (LOSS) TEP TEP Pre- Predecessor Year Ended December 31, 2014 Year Ended December 31, 2013 Period from November 13 to December 31, 2012 Period from January 1 to November 12, 2012 (in thousands, except per unit amounts) (in thousands, except per unit amounts) Revenues: Natural gas liquids sales......................................................... Natural gas sales .................................................................... Natural gas transportation services ........................................ Crude oil transportation services ........................................... Processing and other revenues ............................................... Total Revenues.............................................................. Operating Costs and Expenses: Cost of sales and transportation services (exclusive of depreciation and amortization shown below) ........................ Operations and maintenance .................................................. Depreciation and amortization............................................... General and administrative .................................................... Taxes, other than income taxes.............................................. Total Operating Costs and Expenses............................. Operating Income............................................................................ Other (Expense) Income: Interest (expense) income, net ............................................... Gain on remeasurement of unconsolidated investment ......... Loss on extinguishment of debt ............................................. Equity in earnings of unconsolidated investment .................. Other income, net................................................................... Total Other Income (Expense)...................................... Net Income (Loss) Before Income Taxes ....................................... Texas Margin Taxes............................................................... Net Income (Loss)........................................................................... Net loss attributable to noncontrolling interests .................... Net Income (Loss) attributable to partners ..................................... $ Allocation of income to the limited partners: Net income attributable to partners........................................ $ Predecessor operations interest in net (income) loss ............. Net income attributable to partners, excluding predecessor operations interest .................................................................. Net income attributable to partners prior to May 17, 2013.... Net income attributable to partners subsequent to May 17, 2013........................................................................................ General partner interest in net income subsequent to May 17, 2013.................................................................................. Common and subordinated unitholders' interest in net income subsequent to May 17, 2013..................................... Basic net income per common and subordinated unit ........... $ Diluted net income per common and subordinated unit ........ $ Basic average number of common and subordinated units outstanding............................................................................. Diluted average number of common and subordinated units outstanding............................................................................. 170,924 10,325 126,733 28,343 35,231 371,556 191,654 39,577 47,048 33,160 6,704 318,143 53,413 (7,292) 9,388 — 717 3,103 5,916 59,329 — 59,329 11,352 70,681 70,681 (1,508) 69,173 — 69,173 (7,399) 61,774 $ $ 1.39 1.36 $ $ 44,346 45,394 146,313 9,387 120,025 — 14,801 290,526 146,154 35,404 39,917 27,651 7,401 256,527 33,999 (11,054) — (17,526) — 2,205 (26,375) 7,624 — 7,624 2,123 18,554 2,326 15,970 — 1,722 38,572 19,050 3,921 5,449 8,806 1,277 38,503 69 106,355 15,634 93,214 — 5,089 220,292 101,452 29,901 20,647 11,318 6,861 170,179 50,113 (3,179) 1,661 — — — 492 (2,687) (2,618) — (2,618) 252 — — — 1 1,662 51,775 279 51,496 — 51,496 9,747 $ (2,366) $ 9,747 4,432 14,179 (6,982) 7,197 (206) 6,991 0.17 0.17 40,450 41,458 The accompanying notes are an integral part of these consolidated financial statements. 81 TALLGRASS ENERGY PARTNERS, LP CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) Year Ended December 31, 2014 TEP Year Ended December 31, 2013 (in thousands) Period from November 13 to December 31, 2012 TEP Pre- Predecessor Period from January 1 to November 12, 2012 (in thousands) Net Income (Loss) attributable to partners ................ $ Other Comprehensive Income: Reclassification of change in fair value of derivatives to net income .................................... Change in fair value of derivatives utilized for hedging purposes ................................................ Total Other Comprehensive Loss................ Total comprehensive income (loss) attributable to partners....................................................................... $ 70,681 $ 9,747 $ (2,366) $ 51,496 — — — — — — — — — (4,187) 1,024 (3,163) 70,681 $ 9,747 $ (2,366) $ 48,333 The accompanying notes are an integral part of these consolidated financial statements. 82 TALLGRASS ENERGY PARTNERS, LP CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL TEP Pre- Predecessor Member's Capital TEP Predecessor Member's Capital Predecessor Equity Accumulated Other Comprehensive Income Limited Partners General Partner Common Subordinated Units Amount Units Amount Units Amount Total Partners’ Equity Noncontrolling Interests Total Equity — — — — — — — — — — — $ — — $ — — — — — — — — Balance at January 1, 2012........................ $ 733,717 $ — $ — $ 3,091 — $ Net income to Member.......................... 51,496 Distributions to Member, net................. (57,661) Total change in fair value of derivatives, including a reclassification to earnings ............................................. — — — — — — — — — (3,163) — — — Balance at November 12, 2012 ................. $ 727,552 $ — $ — $ (72) — $ — $ — — — — $ — — — — — — $ — $ 736,808 $ — $ 736,808 — — — — — — 51,496 (57,661) (3,163) — — — 51,496 (57,661) (3,163) — $ — $ 727,480 $ — $ 727,480 206 (363) — — — — — 263 TEP Predecessor's acquisition of TIGT, TMID, Trailblazer and Pony Express.... $ — $ 573,242 $ 122,404 Net loss to Member ............................... — (1,408) (958) Balance at December 31, 2012.................. $ — $ 571,834 $ 121,446 $ $ Net income (loss) attributable to to the period from January 1, 2013 to May 16, 2013................................................. Distributions to Member, net................. Contribution of net assets of TIGT and TMID..................................................... Issuance of units to public (including underwriter over-allotment), net of offering and other costs ......................... Net (loss) income attributable to the period from May 17, 2013 to December 31, 2013 ............................... Distributions to unitholders................... Noncash compensation expense............ Contributions from Predecessor Member, net........................................... — — — — — — — — 6,982 (1,172) (118,538) (460,278) — — — — — — — — (3,260) — — 130,207 — $ — — $ — $ 695,646 — — $ — — — — — — — — $ — — $ (2,366) 693,280 — — — — 5,810 (118,538) $ $ 70,649 (252) 70,397 $ $ 766,295 (2,618) 763,677 (761) 5,049 9,700 167,051 16,200 278,992 827 14,235 — — 14,600 290,483 — — — — — — — — 4,194 (10,685) 4,154 — — — — — — — 2,797 (7,123) — — — — — — — — 290,483 — — — (118,538) — 290,483 2,575 (18,171) 4,154 3,937 (18,171) 4,154 (1,362) — — 130,207 249,665 379,872 Balance at December 31, 2013.................. $ — $ — $ 247,221 $ — 24,300 $ 455,197 16,200 $274,666 827 $ 14,078 $ 991,162 $ 317,939 $ 1,309,101 Net income (loss) .................................. Issuance of units to public (including underwriter over-allotment), net of offering and other costs ......................... Noncash compensation expense............ Distributions to unitholders................... Contribution from TD ........................... (Distributions to) Contributions from Predecessor Member, net ...................... Contributions from Noncontrolling Interest................................................... Distributions to Noncontrolling Interests ................................................. Issuance of general partner units........... Acquisition of Trailblazer...................... Acquisition of Water Solutions ............. Acquisition of 33.3% Pony Express membership interest .............................. — — — — — — — — — — — — — — — — — — — — — — — — 1,508 — — — — (97,887) — — — (91,090) — (59,752) — — — — — — — — — — — — — 39,141 — 22,633 8,079 320,385 — — — — — — — 385 — 70 10,154 (41,567) — — — — — 14,023 — 3,000 — — — — — — — — — — — — — (23,166) — — — — — — — — — — — — — — — — 8 — — — 7,399 70,681 (11,352) 59,329 — — 320,385 10,154 (3,384) (68,117) 27,488 27,488 — — — — 320,385 10,154 (68,117) 27,488 (97,887) 410,012 312,125 — — 263 5,429 5,429 (5,406) — — 1,400 (5,406) 263 (150,000) 1,400 (72,933) (150,000) — — (8,654) (65,406) 38,406 (27,000) Balance at December 31, 2014.................. $ — $ — $ — $ — 32,834 $ 800,333 16,200 $274,133 835 $ (35,743) $ 1,038,723 $ 756,428 $ 1,795,151 The accompanying notes are an integral part of these consolidated financial statements. 83 TALLGRASS ENERGY PARTNERS, LP CONSOLIDATED STATEMENTS OF CASH FLOWS TEP Year Ended December 31, 2014 Year Ended December 31, 2013 (in thousands) Period from November 13 to December 31, 2012 TEP Pre- Predecessor Period from January 1 to November 12, 2012 (in thousands) 59,329 $ 7,624 $ (2,618) $ 51,496 Cash Flows from Operating Activities: Net income (loss).................................................................................................... $ Adjustments to reconcile net income (loss) to net cash flows from operating activities: Depreciation and amortization ................................................................... Gain on remeasurement of unconsolidated investment.............................. Loss on extinguishment of debt.................................................................. Noncash compensation expense................................................................. Changes in components of working capital: Accounts receivable and other ................................................................... Gas imbalances........................................................................................... Inventories .................................................................................................. Accounts payable and accrued liabilities ................................................... Deferred revenue ................................................................................................. Deferred lease payment ....................................................................................... Other operating, net............................................................................................. Net Cash Provided by Operating Activities .............................................................. Cash Flows from Investing Activities: Capital expenditures ............................................................................................ Issuance of related party loan .............................................................................. Acquisition of Trailblazer.................................................................................... Acquisition of additional equity interests in Water Solutions............................. Acquisition of Pony Express membership interest.............................................. Other investing, net ............................................................................................. Net Cash Used in Investing Activities....................................................................... Cash Flows from Financing Activities: Distributions to unitholders ................................................................................. Contribution from TD.......................................................................................... Repayment of debt assumed from TD................................................................. Borrowings under revolving credit facility, net................................................... Proceeds from public offerings, net of offering costs ......................................... Contributions from Predecessor Member, net..................................................... Distributions to Member, net............................................................................... Other financing, net............................................................................................. 49,041 (9,388) — 5,136 (348) 1,504 (8,367) (21,787) 6,619 — (2,295) 79,444 (665,650) (270,000) (150,000) (7,600) (27,000) 17,521 (1,102,729) (68,117) 27,488 — 424,000 320,385 312,125 — 8,271 41,663 — 17,526 1,798 8,506 2,393 (2,807) 12,207 — (4,563) (1,865) 82,482 (346,020) — — — — (1,590) (347,610) (18,171) — (400,000) 135,000 290,483 379,872 (118,538) (3,518) 5,844 — — — 1,425 (318) (214) 5,540 — — 805 10,464 (12,698) — — — — (56) (12,754) — — — — — — — 308 Net Cash Provided by (Used in) Financing Activities .............................................. Net Change in Cash and Cash Equivalents ............................................................... Cash and Cash Equivalents, beginning of period...................................................... Cash and Cash Equivalents, end of period ................................................................ $ 1,024,152 867 — 867 Supplemental Disclosures: Cash payments for interest, net ........................................................................... $ 6,801 Schedule of Noncash Investing and Financing Activities: Property, plant and equipment acquired via the cash management agreement with TD................................................................................................................ $ Distribution to noncontrolling interests settled via the cash management agreement with TD.............................................................................................. $ Increase in accrual for payment of property, plant and equipment ..................... $ Increase in accrual for reimbursable construction in progress projects .............. $ Fair value of TIGT and TMID assets contributed by TD.................................... $ Fair value of TIGT and TMID liabilities contributed by TD .............................. $ Fair value of assets acquired by TEP Predecessor .............................................. $ Fair value of liabilities acquired by TEP Predecessor......................................... $ 265,128 — — — $ 308 (1,982) 1,982 — $ 3,450 $ — $ — $ — $ — $ — $ $ $ $ $ — $ — $ — $ — $ — $ — $ 90,373 14,470 1,027,127 (566,849) $ $ $ $ — $ — $ 5,325 $ — $ — $ — $ $ $ 1,230,618 (464,323) 158,357 5,361 The accompanying notes are an integral part of these consolidated financial statements. 84 20,647 — — — (3,749) 4,551 (98) 6,286 — — 2,202 81,335 (19,540) — — — — (2,152) (21,692) — — — — — — (57,661) — (57,661) 1,982 — 1,982 — — — 1,939 — — — — — TALLGRASS ENERGY PARTNERS, LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Description of Business Tallgrass Energy Partners, LP ("TEP" or the "Partnership") is a Delaware limited partnership formed in February 2013. TEP closed its initial public offering ("IPO") on May 17, 2013 and on July 25, 2014 closed a public offering of an additional 8,050,000 common units. The 22,678,625 common units held by the public constitute approximately 46.3% of TEP’s aggregate outstanding common and subordinated units and approximately 45.5% of TEP’s aggregate outstanding common, subordinated and general partner units at December 31, 2014. Tallgrass Development, LP ("TD") held 10,155,480 common units and 16,200,000 subordinated units at December 31, 2014, which comprised approximately 53.7% of TEP’s aggregate outstanding common and subordinated units and approximately 52.8% of TEP’s aggregate outstanding common, subordinated and general partner units. The 16,200,000 subordinated units outstanding at December 31, 2014 were converted to common units on February 17, 2015, as discussed further in Note 11 - Partnership Equity and Distributions. In addition, 834,391 general partner units, representing an approximate 1.7% general partner interest in TEP at December 31, 2014, and all of the incentive distribution rights ("IDRs") are held by Tallgrass MLP GP, LLC (the "general partner"). The terms "TEP Predecessor" and "TEP Pre-Predecessor" refer to Tallgrass Energy Partners Predecessor and Tallgrass Energy Partners Pre-Predecessor, which are comprised of the businesses described below that were owned by Kinder Morgan Energy Partners, LP ("TEP Pre-Predecessor Parent") prior to November 13, 2012. On November 13, 2012, TEP Pre- Predecessor Parent sold those assets, among others, to TD. The businesses included in the TEP Pre-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 4,653 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 natural gas processing plants in Wyoming. Prior to the sale of these assets to TD on November 13, 2012, TIGT was named Kinder Morgan Interstate Gas Transmission LLC and TMID was named KM Upstream LLC. In addition to TIGT and TMID, the businesses included in the TEP Predecessor consist of: • Trailblazer Pipeline Company LLC ("Trailblazer"), which TEP acquired from TD on April 1, 2014. Trailblazer is an approximately 436-mile FERC regulated natural gas pipeline system that begins along the border of Wyoming and Colorado and extends to Beatrice, Nebraska. • Tallgrass Pony Express Pipeline, LLC ("Pony Express"), of which TEP acquired a 33.3% membership interest effective September 1, 2014. Pony Express owns and operates the Pony Express System, an approximately 698-mile crude oil pipeline commencing in Guernsey, Wyoming, and terminating in Cushing, Oklahoma, with delivery points at the Ponca City Refinery and at Deeprock in Cushing. Upon completion of ongoing construction, Pony Express also will own an approximately 66-mile lateral in Northeast Colorado that will commence in Weld County, Colorado, and interconnect with the Pony Express System just east of Sterling, Colorado. The lateral in Northeast Colorado is expected to be in service sometime during the first half of 2015. TD owns the remaining 66.7% membership interest in Pony Express. The term "Trailblazer Predecessor" refers to Trailblazer for the period from November 13, 2012 to its acquisition by TEP on April 1, 2014, and the term "Pony Express Predecessor" refers to Pony Express for the period from November 13, 2012 to September 1, 2014, the date on which TEP acquired a 33.3% membership interest. TEP Predecessor, Trailblazer Predecessor and Pony Express Predecessor are collectively referred to as the Predecessor Entities, as further discussed in Note 2 – Summary of Significant Accounting Policies. Financial results for all prior periods subsequent to November 13, 2012, the date common control was established, have been recast to reflect the operations of the Predecessor Entities. Predecessor Equity as presented in the consolidated financial statements represents the capital account activity of Trailblazer Predecessor from November 13, 2012 to April 1, 2014 and of Pony Express Predecessor from November 13, 2012 to September 1, 2014. For additional information regarding these acquisitions, see Note 4 – Acquisitions. 85 2. Summary of Significant Accounting Policies Basis of Presentation The accompanying financial statements and related notes were prepared in accordance with the generally accepted accounting principles contained in the Financial Accounting Standards Board’s Accounting Standards Codification ("GAAP"). 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. The accompanying combined financial statements for TEP Pre-Predecessor for the period from January 1, 2012 to November 12, 2012, are presented on a "held in use" basis. 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 Pony Express for the periods prior to September 1, 2014, the date TEP acquired a 33.3% membership interest in Pony Express, 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 have 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 4 – Acquisitions, TEP closed the acquisition of Trailblazer on April 1, 2014 and the acquisition of a 33.3% membership interest in Pony Express effective September 1, 2014. As the acquisitions of Trailblazer and Pony Express are considered transactions between entities under common control, and a change in reporting entity, the financial information presented for prior periods has been recast to include Trailblazer and Pony Express for all periods subsequent to November 13, 2012. The combined financial statements of the Predecessor Entities include legal entities, as detailed above, that are indirect wholly-owned subsidiaries of the Predecessor Entities. As the combined financial statements reflect TEP Predecessor and TEP Pre-Predecessor as single entities, significant intra-entity items have been eliminated in the presentation. Net equity distributions of the TEP Predecessor and the Predecessor Entities included in the Consolidated Statements of Cash Flows represent transfers of cash as a result of TD and TEP Pre-Predecessor Parent’s centralized cash management systems prior to May 17, 2013, and prior to April 1, 2014 for Trailblazer and September 1, 2014 for Pony Express, 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. Pony Express participates in a cash management agreement with TD, which holds a 66.7% common membership interest in Pony Express, under which cash balances are swept daily and recorded as loans from Pony Express to TD. Net income or loss from consolidated subsidiaries that are not wholly-owned by TEP is attributed to TEP and noncontrolling interests. This is done in accordance with substantive profit sharing arrangements, which generally follow the allocation of cash distributions and may not follow the respective ownership percentages held by TEP. Concurrent with TEP's acquisition of a 33.3% membership interest in Pony Express, TEP, TD, and Pony Express entered into the Second Amended and Restated Limited Liability Agreement of Tallgrass Pony Express Pipeline, LLC ("the Pony Express LLC Agreement"). The Pony Express LLC Agreement provides that the net income or loss of Pony Express be allocated, to the extent possible, consistent with the allocation of Pony Express cash distributions. The Pony Express LLC Agreement provides TEP a minimum quarterly preference payment of $16.65 million through the quarter ending September 30, 2015. For periods beginning after September 30, 2015 distributions and net income or loss from Pony Express will be attributed to TEP and noncontrolling interests in accordance with the respective ownership interests. 86 A variable interest entity ("VIE") is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has a variable interest that could be significant to the VIE and the power to direct the activities that most significantly impact the entity’s economic performance. TEP has presented separately on its consolidated balance sheets, to the extent material, the assets of its consolidated VIE that can only be used to settle specific obligations of the consolidated VIE, and the liabilities of TEP's consolidated VIE for which creditors do not have recourse to TEP's general credit. Pony Express is considered to be a VIE under the applicable authoritative guidance. Based on a qualitative analysis in accordance with the applicable authoritative guidance, TEP has determined that it has the power to direct matters that most significantly impact the activities of Pony Express and has the right to receive benefits of Pony Express that could potentially be significant to Pony Express. TEP has consolidated Pony Express as TEP is the primary beneficiary. For additional information see Note 3 – Variable Interest Entities. TEP's financial results as presented on the consolidated statements of income (loss), comprehensive income and cash flows have been separated from TEP Pre-Predecessor's combined financial results by a bold vertical black line. Use of Estimates Certain amounts included in or affecting these 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. Cash and Cash Equivalents TEP and the TEP Pre-Predecessor consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Prior to November 12, 2012, the TEP Pre-Predecessor Parent employed a centralized cash management system that was utilized for its wholly-owned subsidiaries. Subsequent to November 13, 2012, TIGT and TMID entered into similar cash management agreements with TD. In accordance with the cash management agreements, the subsidiary companies make loans on each business day equal to the amount swept from their depository bank accounts. At the beginning of the following month, the total of these loans for each company, less reimbursement payments under the agency agreements described below in Note 5 - Related Party Transactions, is transferred to an interest bearing account and are subsequently, periodically recorded as equity distributions. This practice was discontinued effective May 17, 2013, when TIGT and TMID were contributed to TEP. Subsequent to May 17, 2013, all payable and receivable balances between TEP and TD are cash settled with the exception of certain balances payable from Pony Express to TD, which have been settled against the receivable from TD via the Pony Express cash management agreement. Net equity distributions of the Predecessor Entities 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 and September 1, 2014 for Pony Express, 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. Pony Express participates in a cash management agreement with TD, which holds a 66.7% common membership interest in Pony Express, under which cash balances are swept daily and recorded as loans from Pony Express to TD. Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable are carried at their estimated collectible amounts. TEP and TEP Pre-Predecessor make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and adjustments are recorded as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. Our allowance for doubtful accounts totaled $0.5 million and $0.8 million at December 31, 2014 and 2013, respectively. 87 Inventories Inventories primarily consist of gas in underground storage, materials and supplies, natural gas liquids and crude oil. Natural gas liquids and gas in underground storage, sometimes referred to as working gas, are recorded at the lower of historical cost or market using the average cost method. As discussed further under "Revenue Recognition" below, a loss allowance is factored into the crude oil tariffs to offset losses in transit. As crude oil is transported, TEP earns oil for its services as pipeline allowance oil, which it can then sell. As pipeline allowance oil is accumulated, it is recorded as inventory at the lower of historical cost or market using the average cost method. Materials and supplies are valued at weighted average cost and periodically reviewed for physical deterioration and obsolescence. For additional information, see "Gas in Underground Storage" below. Accounting for Regulatory Activities Regulated activities are accounted for in accordance with the "Regulated Operations" Topic of the Codification. This Topic prescribes the circumstances in which the application of GAAP is affected by the economic effects of regulation. Regulatory assets and liabilities represent probable future revenues or expenses to TEP and TEP Pre-Predecessor associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. TEP had recorded regulatory assets of approximately $1.4 million and $1.3 million included in "Deferred charges and other assets" in the Consolidated Balance Sheets at December 31, 2014 and 2013, respectively. Regulatory assets at December 31, 2014 and 2013 were primarily attributable to costs associated with Trailblazer’s 2013 Rate Case Filing as more fully described in Note 16 – Regulatory Matters and costs associated with the Predecessor Entities’ participation in the TEP Pre-Predecessor entity’s postemployment benefit plans. Property, Plant and Equipment Property, plant and equipment was adjusted to fair value on November 13, 2012, the date the acquisition of TIGT, TMID and Trailblazer by TD was completed. For additional information see Note 4 - Acquisitions. Property, plant and equipment is stated at historical cost, which for constructed plants includes indirect costs such as payroll taxes, other employee benefits, allowance for funds used during construction for regulated assets and other costs directly related to the projects. Expenditures that increase capacities, improve efficiencies or extend useful lives are capitalized and depreciated over the remaining useful life of the asset or major asset component. We also capitalize certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs. Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of the regulated depreciable utility property, plant and equipment, plus the cost of removal less salvage value and any gain or loss recognized, is recorded in accumulated depreciation with no effect on current period earnings. Gains or losses are recognized upon retirement of non-regulated or regulated property, plant and equipment constituting an operating unit or system, and land, when sold or abandoned and costs of removal or salvage are expensed when incurred. Intangible Assets TEP accounts for intangible assets in accordance with ASC 805, which established that an intangible asset is identifiable if it meets either the separability criterion or the contractual-legal criterion. Further, in accordance with ASC 805, contract-based intangible assets represent the value of rights that arise from contractual arrangements. Use rights such as drilling, water, air, timber cutting, and route authorities are an example of contract-based intangible assets. Intangible assets arose at Pony Express from the acquisition of rights associated with the ability and regulatory permissions to convert a section of TIGT's natural gas pipeline, which was subsequently purchased by Pony Express, to crude oil and includes the operational and financial benefits that accrue due to those rights and the ability to make that asset more valuable ("the Pony Express oil conversion use rights"). These intangible assets are amortized on a straight-line basis over a period of 35 years, the period of expected future benefit. Intangible assets arose at BNN Redtail, LLC ("Redtail") as a result of a significant customer contract with favorable market terms which was acquired as part of the Water Solutions transaction discussed in Note 4 - Acquisitions. These intangible assets are amortized on a straight-line basis over a period of 1.6 years, the remaining term of the contract at the time of acquisition. Impairment of Long-Lived Assets TEP and TEP Pre-Predecessor review their long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss results when the estimated undiscounted future net cash flows expected to result from the asset’s use and its eventual disposition are less than its carrying amount. TEP and TEP Pre-Predecessor assess their long-lived assets for impairment in accordance with the relevant Codification guidance. A long-lived asset is tested for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair value. 88 Examples of long-lived asset impairment indicators include: • • • • • • a significant decrease in the market value of a long-lived asset or group; a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition; a significant adverse change in legal factors or in the business climate could affect the value of long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process; an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the long-lived asset or asset group; a current period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. When an impairment indicator is present, TEP and TEP Pre-Predecessors first assess the recoverability of the long-lived assets by comparing the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset to the carrying amount of the asset. If the carrying amount is higher than the undiscounted future cash flows, the fair value of the assets is assessed using a discounted cash flow analysis and used to determine the amount of impairment, if any, to be recognized. Gas in Underground Storage Gas in underground storage represents the cost of base gas, which refers to the volumes necessary to maintain pressure and deliverability requirements in TEP and TEP Pre-Predecessors’ storage facilities. TEP and TEP Pre-Predecessor record base gas as a component of property, plant and equipment. TEP maintains working gas in its underground storage facilities on behalf of certain third parties. TEP receives a fee for its storage services but does not reflect the value of third party gas in the accompanying consolidated financial statements. TEP occasionally acquires volumes of working gas for its own account. These volumes of working gas are recorded as natural gas inventory at the lower of cost or market. Prior to November 12, 2012, TEP Pre-Predecessor recorded these volumes of working gas at historical cost as a component of property, plant and equipment. Depreciation and Amortization - Regulated Assets TEP Pre-Predecessor computed depreciation using a composite method employed by applying a single depreciation rate to a group of assets with similar economic characteristics. This composite method of depreciation approximates a straight-line method of depreciation. TEP has elected to continue to use the composite depreciation method for its regulated assets at TIGT and Trailblazer. The annualized rate of depreciation ranges from 1.55% to 20.00% for the various classes of depreciable, regulated assets. Depreciation and Amortization - Non-regulated Assets For non-regulated assets, TEP has elected to use the straight-line method of depreciation. The useful lives for the various classes of non-regulated depreciable assets are as follows: Range of Useful Lives (in years) Crude oil pipelines........................ Processing & Treating................... Natural gas pipelines (1)................. General & Other ........................... 35 30 10 3-13 1/3 (1) Includes the Replacement Gas Facilities as discussed in Note 5 - Related Party Transactions and Note 16 - Regulatory Matters. 89 Gas Imbalances Gas imbalances receivable and payable represent the difference between customer nominations and actual gas receipts from and gas deliveries to interconnecting pipelines under various operational balancing and imbalance agreements. Gas imbalances are either made up in-kind or settled in cash, subject to the terms and valuations of the various agreements. Imbalances are valued at the Average Monthly Index Price ("AMIP") of the Colorado Interstate Gas Index ("CIG") and Panhandle Eastern Pipeline Gas Index ("PEPL"). Deferred Financing Costs Costs incurred in connection with the issuance of long-term debt are deferred and amortized over the related financing period using the effective interest method. Deferred financing costs were allocated from TD to TEP on November 13, 2012 as discussed in Note 4 - Acquisitions. Deferred financing costs allocated from TD were amortized over the related financing period using the effective interest method and subsequently written off as a loss on extinguishment of debt upon repayment of the long-term debt allocated from TD on May 17, 2013. See Note 10 - Long-term Debt for additional information. Goodwill As discussed in Note 4 - Acquisitions, we recorded goodwill in connection with the acquisition of TIGT, Trailblazer and TMID in 2012 and the acquisition of Water Solutions in 2014. TEP evaluates goodwill for impairment on an annual basis and whenever events or changes in circumstances necessitate an evaluation for impairment. Examples of such facts and circumstances include the magnitude of the excess of the fair value over the carrying amount in the last valuation or changes in the business environment. TEP’s annual impairment testing date is August 31st. TEP evaluates goodwill for impairment at the reporting unit level, which is an operating segment as defined in the segment reporting guidance of the Codification, using either the qualitative assessment option or the two-step test approach depending on facts and circumstances of the reporting unit. If TEP, after performing the qualitative assessment, determines it is "more likely than not" that the fair value of a reporting unit is greater than its carrying amount, the two-step impairment test is unnecessary. When goodwill is evaluated for impairment using the two-step test, the carrying amount of the reporting unit is compared to its fair value in Step 1 and if the fair value exceeds the carrying amount, Step 2 is unnecessary. If the carrying amount exceeds the reporting unit’s fair value, this could indicate potential impairment and Step 2 of the goodwill evaluation process is required to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any. When Step 2 is necessary, the fair value of individual assets and liabilities is determined using valuations, or other observable sources of fair value, as appropriate. If the carrying amount of goodwill exceeds its implied fair value, the excess is recognized as an impairment loss. See Note 8 - Goodwill and Other Intangible Assets for additional information. Investment in Unconsolidated Affiliates We use the equity method to account for investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and for investments in less than 20% owned affiliates where we have the ability to exercise significant influence. We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in value, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. We assess the fair value of our investments in unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. The difference between the carrying amount of the unconsolidated affiliates and their estimated fair value is recognized as an impairment loss when the loss in value is deemed to be other-than-temporary. TEP’s investment in Grasslands Water Services I, LLC ("GWSI"), which owns a water transportation pipeline, was initially recorded under the equity method of accounting as TEP had the ability to exercise significant influence, but not control, over this investment. As of December 31, 2013, the carrying amount of TEP’s investment in GWSI of $1.3 million consisted of cash contributions made during the year ended December 31, 2013 and was reported within the line item "Deferred charges and other assets" on the consolidated balance sheet. There was $0.7 million equity in earnings recognized for the year ended December 31, 2014. There was no equity in earnings recognized for the year ended December 31, 2013. As discussed in Note 4 - Acquisitions, during the year ended December 31, 2014, TEP acquired a controlling interest in GWSI, which was subsequently renamed BNN Redtail, LLC ("Redtail"), and consolidated its investment in Redtail as of May 13, 2014 accordingly. 90 Revenue Recognition TEP and TEP Pre-Predecessor recognize revenues as services are rendered or goods are sold to a purchaser at a fixed and determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. TEP and TEP Pre- Predecessor provide various types of natural gas storage and transportation services and crude oil transportation services to their customers in which the commodity remains the property of these customers at all times. Natural gas liquids sales occur in the Processing & Logistics segment and consist of the sale of outputs from our processing plants and the marketing of natural gas liquids that are delivered by our suppliers under either fee-based arrangements or percent-of-proceeds arrangements. Under these arrangements, we treat and process the natural gas delivered by our suppliers, and then sell the resulting NGLs and condensate based on published index market prices. We remit to the producers an agreed-upon percentage of the actual proceeds that we receive from our sales of the NGLs and condensate. We keep the difference between the proceeds received and the amount remitted back to the producer. We generally report revenues gross in the consolidated statements of income, as we typically act as the principal in these transactions, take custody to the product, and incur the risks and rewards of ownership. Processing and other revenues primarily represent processing fees for processing, treating and fractionation of natural gas earned under fee-based arrangements and revenue from water services earned in the Processing & Logistics segment. Natural gas sales occur in both the Natural Gas Transportation & Logistics segment and in the Processing & Logistics segment. In the Natural Gas Transportation & Logistics segment, transportation services revenue is recognized when a portion of the natural gas transported by customers is collected as a contractual fee to compensate TEP and TEP Pre-Predecessor for fuel consumed by pipeline and storage operations. We take title and record revenue at market prices when the volumes included in the contractual fee are delivered from the customer and injected into our storage facility. When the excess volumes are eventually sold we record natural gas sales revenue at the contractual sales price and cost of sales and transportation services at average cost. In addition, when operational conditions allow, TEP and TEP Pre-Predecessor occasionally sell "base gas," which refers to the minimum volume of natural gas required in order to operate the storage facility. In the Processing & Logistics segment, we purchase natural gas primarily for use in our operations and for meeting contractual requirements to deliver natural gas to certain customers. In addition, some of our contractual arrangements allow us to keep a portion of the processed natural gas as compensation for processing services. We generate revenue by selling the volumes of natural gas received or purchased that exceed our business needs. Natural gas transportation services occur in the Natural Gas Transportation & Logistics segment. In many cases (generally described as "firm service"), the customer pays a two-part rate that includes (i) a fee reserving the right to transport or store natural gas in TEP and TEP Pre-Predecessors’ facilities and (ii) a per-unit rate for volumes actually transported or injected into/ withdrawn from storage. The fee-based component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/withdrawn from TEP and TEP Pre-Predecessors’ storage facilities. In other cases (generally described as "interruptible service"), there is no fee associated with the services because the customer accepts the possibility that service may be interrupted at TEP and TEP Pre-Predecessors’ discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements. In addition to "firm" and "interruptible" transportation services, TEP and TEP Pre-Predecessor also provide natural gas park and loan services to assist customers in managing short- term gas surpluses or deficits. Revenues are recognized as services are provided, based on the terms negotiated under these contracts. Crude oil transportation services occur in the Crude Oil Transportation & Logistics segment. TEP provides various types of crude oil transportation services to its customers and, other than pipeline allowance oil, does not take title to the crude oil and does not incur the risks and rewards of ownership. In many cases the customer has committed to ship a fixed quantity of oil barrels per month. For barrels physically received by TEP and delivered to the customers’ agreed upon destination point, revenue is recognized in the period the service is provided. Shipper deficiencies, or barrels committed by the customer to be transported in a month but not physically received by TEP for transport or delivered to the customers’ agreed upon destination point are charged at the committed tariff rate per barrel and recorded as a deferred liability until the barrels are physically transported and delivered by TEP. In the case of non-committed shippers, revenue is recognized in the same manner utilized for the barrels physically transported and delivered. A loss allowance is factored into the crude oil tariffs to offset losses in transit. As crude oil is transported, TEP earns oil for its services as pipeline allowance oil. Any pipeline allowance oil that remains after replacing losses in transit can be sold. We take title and record revenue at market prices when the volumes included in the pipeline loss allowance are delivered from the customer. When pipeline loss allowance oil is eventually sold we record revenue at the contractual sales price and cost of sales and transportation services at average cost as discussed in "Inventories" above. There were no sales of pipeline allowance oil during the year ended December 31, 2014. 91 Commitments and Contingencies We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss. Environmental Costs TEP and TEP Pre-Predecessor expense or capitalize, as appropriate, environmental expenditures that relate to current operations. TEP and TEP Pre-Predecessors’ expense amounts that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation. TEP and TEP Pre-Predecessor do not discount environmental liabilities to a net present value, and record environmental liabilities when environmental assessments and/or remedial efforts are probable and costs can be reasonably estimated. Recording of these accruals coincides with the completion of a feasibility study or a commitment to a formal plan of action. Estimates of environmental liabilities are based on currently available facts and presently enacted laws and regulations taking into consideration the likely effects of other factors including our prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual cost or new information. Fair Value Fair value, as defined in the Codification, is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. TEP and TEP Pre-Predecessor apply the fair value measurement guidance to financial assets and liabilities in determining the fair value of derivative assets and liabilities, and to nonfinancial assets and liabilities upon the acquisition of a business or in conjunction with the measurement of an impairment loss on an asset group or goodwill under the accounting guidance for the impairment of long-lived assets or goodwill. The fair value measurement accounting guidance requires that TEP and TEP Pre-Predecessor make assumptions that market participants would use in pricing an asset or liability based on the best information available. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk of the reporting entity (for liabilities) and of the counterparty (for assets). The fair value measurement guidance prohibits the inclusion of transaction costs and any adjustments for blockage factors in determining the instruments’ fair value. The principal or most advantageous market should be considered from the perspective of the reporting entity. Fair value, where available, is based on observable market prices. Where observable market prices or inputs are not available, different valuation models and techniques are applied. These models and techniques attempt to maximize the use of observable inputs and minimize the use of unobservable inputs. The process involves varying levels of management judgment, the degree of which is dependent on the price transparency of the instruments or market and the instruments’ complexity. To increase consistency and enhance disclosure of fair value, the Codification creates a fair value hierarchy to prioritize the inputs used to measure fair value into three categories. An asset or liability’s level within the fair value hierarchy is based on the lowest level of input significant to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest. The three levels are defined as follows: • Level 1 Inputs-quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date; • Level 2 Inputs-inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and • Level 3 Inputs-unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data). Any transfers between levels within the fair value hierarchy are recognized at the end of the reporting period. For information regarding financial instruments measured at fair value on a recurring basis, see Note 9 - Risk Management. For information regarding the fair value of financial instruments not measured at fair value in the Consolidated Balance Sheets, see Note 10 - Long-term Debt. 92 Risk Management Activities TEP and TEP Pre-Predecessor utilize energy derivatives for the purpose of mitigating its risk resulting from fluctuations in the market price of natural gas. TEP and TEP Pre-Predecessor record derivative contracts at their estimated fair values as of each reporting date. TEP Pre-Predecessor designated certain derivative instruments as qualifying hedges. TEP has elected not to apply hedge accounting for these derivative instruments. For more information on TEP and TEP Pre-Predecessors’ risk management activities, see Note 9 - Risk Management. Equity-Based Compensation Equity-based compensation grants are measured at their grant date fair value and related compensation cost is recognized over the vesting period of the grant. Compensation cost for awards with graded vesting provisions is recognized on a straight- line basis over the requisite service period of each separately vesting portion of the award. As discussed in Note 15 - Equity- Based Compensation, a portion of the expense recognized relating to equity-based compensation grants is charged to TD. Income Taxes Prior to September 1, 2014, TEP was comprised solely of limited liability companies that have elected to be treated as partnerships for income tax purposes. As discussed above, effective September 1, 2014 TEP acquired a 33.3% membership interest in Pony Express, which in turn owns 99.8% of Tallgrass Pony Express Pipeline (Colorado), Inc. ("PXP Colorado"), a C corporation. PXP Colorado is currently in the process of constructing a lateral pipeline on the Pony Express System located in Northeast Colorado and has not yet commenced operations or generated any income. Accordingly, no provision for federal or state income taxes has been recorded in the financial statements of TEP and TEP Pre-Predecessor and the tax effects of TEP and TEP Pre-Predecessors' activities accrue to their parents. TEP Pre-Predecessor historically incurred Texas Margin Taxes because it was part of an affiliated group that generated sales in the State of Texas. Accounting Pronouncements Issued But Not Yet Effective 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. TEP is currently evaluating the impact of ASU 2014-09. ASU No. 2014-12, "Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period" In June 2014, The FASB issued ASU No. 2014-12, Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. ASU 2014-12 provides explicit guidance on accounting for share-based payments requiring a specific performance target to be achieved in order for employees to become eligible to vest in the awards when that performance target may be achieved after the requisite service period for the award. The ASU requires that such performance targets be treated as a performance condition, and should not be reflected in the estimate of the grant-date fair value of the award. Instead, compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved. ASU 2014-12 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption is permitted. The adoption of ASU 2014-12 is not expected to have a material impact on TEP's financial position and results of operations. 93 3. Variable Interest Entities TEP, as the managing member of Pony Express, has voting rights disproportionate to its ownership interest. In addition, TEP does not have the obligation to absorb expected losses as a result of the minimum quarterly preference payments as discussed in Note 4 – Acquisitions. As a result, TEP has determined that Pony Express is a VIE of which TEP is the primary beneficiary and consolidates Pony Express accordingly. TEP has not provided any additional financial support to Pony Express other than its initial capital contribution of $570 million and has no contractual commitments or obligations to provide additional financial support. In the event that the costs of construction of the Pony Express System and lateral in Northeast Colorado exceed the $270 million retained by Pony Express as discussed in Note 4 – Acquisitions, TD is obligated to fund the remaining costs. The carrying amounts and classifications of the Pony Express assets and liabilities included in TEP's consolidated balance sheet at December 31, 2014 and December 31, 2013 are as follows: Current assets ........................................................................................ $ Noncurrent assets .................................................................................. Total assets..................................................................................... $ Current liabilities................................................................................... $ Total liabilities ............................................................................... $ December 31, 2014 December 31, 2013 (in thousands) 93,019 1,300,816 1,393,835 52,547 52,547 $ $ $ $ — 566,156 566,156 89,247 89,247 4. Acquisitions Asset Acquisitions by TD On November 13, 2012, TD completed the acquisition of certain assets from TEP Pre-Predecessor Parent for approximately $1.8 billion in cash and approximately $1.5 billion of assumed debt. The acquisition included a 100% equity interest in TIGT, TMID, Trailblazer and Pony Express, as discussed in Note 1 – Description of Business. Of the approximately $1.8 billion in cash paid to acquire all of the net assets, $766.3 million was allocated to TIGT, TMID, Trailblazer and Pony Express. At December 31, 2012, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. During the year ended December 31, 2013, the preliminary purchase price allocation was adjusted for certain immaterial items related to regulatory assets and accrued liabilities. The regulation of natural gas pipelines is an integral attribute of the assets contributed by TD in connection with the IPO and therefore was included in the determination of the fair value of the regulated assets. The Pre-Predecessor’s net book value of natural gas pipeline assets was higher than the historical regulatory net book value, and a comparative decrease in the gross book value of the natural gas pipelines resulted from adjusting the regulatory assets to their approximate fair value. The new basis of property, plant and equipment at December 31, 2012 represents the fair value on November 13, 2012 of the assets contributed to us by TD plus capital expenditures made through December 31, 2012. The fair value on November 13, 2012 of the regulated assets contributed to us by TD in connection with the IPO approximated the net book value of those assets on a regulated basis. The fair value of the non-regulated assets contributed to us by TD approximated their replacement cost values on November 13, 2012 and reflect a higher fair market value as compared to the Pre-Predecessor’s basis. 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 concurrently with the IPO, and was therefore allocated to TIGT and TMID along with the related deferred financing costs at November 13, 2012. On May 17, 2013, concurrently with the closing of the IPO, this $400 million of the long-term debt held by TD was assumed and repaid by TEP. TIGT and TMID were also released as guarantors of the TD debt and became guarantors of the TEP revolving credit facility. For additional information, see Note 10 – Long-term Debt. Pro forma revenue and net income for the period from January 1, 2012 to November 12, 2012 was $220.3 million and $25.9 million, respectively. The unaudited pro forma financial information for the historical period is presented as if the acquisition of TIGT and TMID had been completed on January 1, 2012. 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 Pre-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. 94 Pro forma revenue contains no adjustments to the historical amounts. Pro forma net income includes adjustments for the period from January 1, 2012 to November 12, 2012 to give effect to the following: (a) Reduction in net income to reflect additional depreciation expense associated with the increase in the cost of property, plant and equipment that resulted from the allocation of the purchase price to the fair value of the assets and liabilities acquired by TD. (b) Reduction in net income to reflect interest expense on the long-term debt allocated to TIGT and TMID in connection with the acquisition of TIGT and TMID by TD. The subsequent contribution of the assets and liabilities of TIGT and TMID from TD to TEP, which was effective on May 17, 2013, was accounted for as a transaction between entities under common control under ASC 805. TEP Acquisition of Trailblazer On April 1, 2014, TEP closed the acquisition of Trailblazer from a wholly owned subsidiary of TD for total consideration valued at approximately $164 million, consisting of $150 million in cash and the issuance of 385,140 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 11 – Partnership Equity and Distributions. TEP Acquisition of 33.3% of Pony Express Effective September 1, 2014, TEP acquired a 33.3% membership interest in Pony Express for total consideration of approximately $600 million. At closing, Pony Express, TD, and TEP entered into a Second Amended and Restated Limited Liability Company Agreement of Pony Express effective September 1, 2014, which sets forth the relative rights of TD and TEP as the owners of Pony Express. Of the total consideration of $600 million, TEP directly paid TD $30 million, consisting of $27 million in cash and 70,340 TEP common units with an aggregate fair value of approximately $3 million, in exchange for the transfer by TD to TEP of a 1.9585% membership interest in Pony Express (computed before giving effect to the issuance of the new membership interest by Pony Express to TEP). TEP also contributed cash of $570 million to Pony Express in exchange for a newly issued membership interest which, when combined with the membership interest transferred from TD and the parties' entry at closing into the Second Amended and Restated Limited Liability Company Agreement of Pony Express, constitutes TEP's 33.3% membership interest in Pony Express, which represents 100% of the preferred membership units issued by Pony Express. Of the $570 million cash consideration received by Pony Express, $300 million was immediately distributed to TD at closing and $270 million is maintained by Pony Express to fund the estimated remaining costs of construction for the Pony Express System and the lateral in Northeast Colorado. The $270 million cash balance was subsequently swept to TD under a cash management agreement between Pony Express and TD and was recorded as a related party loan which bears interest at TD's incremental borrowing rate. The terms of the transaction provide TEP a minimum quarterly preference payment of $16.65 million through the quarter ending September 30, 2015 (prorated to approximately $5.4 million for the quarter ended September 30, 2014) with distributions thereafter shared in accordance with the terms of the Second Amended and Restated Limited Liability Company Agreement of Pony Express. TEP has determined that Pony Express is a VIE of which TEP is the primary beneficiary, and consolidates Pony Express accordingly. For additional discussion and disclosure, see Note 3 – Variable Interest Entities. The acquisition of Pony Express represents a transaction between entities under common control and a change in reporting entity. 95 Historical Financial Information The results of our acquisitions of Trailblazer and Pony Express are included in the consolidated balance sheets as of December 31, 2014 and December 31, 2013. The following table presents the previously reported December 31, 2013 consolidated balance sheet, adjusted for the acquisitions of Trailblazer and Pony Express: As of December 31, 2013 Consolidate Trailblazer Pipeline Company LLC Consolidate Tallgrass Pony Express Pipeline, LLC (in thousands) TEP (As currently reported) TEP ASSETS Current Assets: Accounts receivable, net .................................. $ 27,615 $ 2,418 $ — $ $ $ Gas imbalances................................................. Inventories ........................................................ Prepayments and other current assets............... Total Current Assets.................................. Property, plant and equipment, net.......................... Goodwill .................................................................. Intangible asset, net ................................................. Deferred financing costs.......................................... Deferred charges and other assets ........................... Total Assets.............................................................. LIABILITIES AND PARTNERS’ EQUITY Current Liabilities: Accounts payable ............................................. Accounts payable to related parties.................. Gas imbalances................................................. Derivative liabilities at fair value ..................... Accrued taxes ................................................... Accrued liabilities ............................................ Deferred revenue .............................................. Other current liabilities..................................... Total Current Liabilities............................ Long-term debt ........................................................ Other long-term liabilities and deferred credits....... Total Long-term Liabilities ....................... Equity: Net Equity ........................................................ Total Equity............................................... 2,598 5,148 16,986 52,347 594,911 304,474 — 4,512 11,554 530 401 — 3,349 62,869 30,241 — — 1,000 — — — — 459,026 — 102,567 — 4,563 30,033 3,128 5,549 16,986 55,696 1,116,806 334,715 102,567 4,512 17,117 967,798 $ 97,459 $ 566,156 $ 1,631,413 54,621 $ 5,619 $ 89,212 $ 149,452 7,134 3,142 184 4,427 4,556 538 9,683 84,285 135,000 4,572 139,572 743,941 743,941 3 522 — 1,093 959 — 1,012 9,208 — — — — — — — 35 — — 89,247 — — — 7,137 3,664 184 5,520 5,550 538 10,695 182,740 135,000 4,572 139,572 88,251 88,251 476,909 476,909 1,309,101 1,309,101 Total Liabilities and Equity ..................................... $ 967,798 $ 97,459 $ 566,156 $ 1,631,413 96 The results of our acquisitions of Trailblazer and Pony Express are included in the consolidated statements of income for the year ended December 31, 2014, the year ended December 31, 2013, and the period from November 13 to December 31, 2012. The following tables present the previously reported consolidated statements of income for the year ended December 31, 2013 and the period from November 13 to December 31, 2012, adjusted for the acquisitions of Trailblazer and Pony Express: Year Ended December 31, 2013 Consolidate Trailblazer Pipeline Company LLC Consolidate Tallgrass Pony Express Pipeline, LLC (in thousands) TEP (As currently reported) TEP Revenues: Natural gas liquids sales ................................ $ 146,313 $ — $ — $ 146,313 Natural gas sales ............................................ Transportation services.................................. Processing and other revenues....................... Total Revenues ....................................... Operating Costs and Expenses: Cost of sales and transportation services....... Operations and maintenance.......................... Depreciation and amortization ...................... General and administrative............................ Taxes, other than income taxes...................... Total Operating Costs and Expenses...... Operating Income (Loss) ...................................... Other (Expense) Income: Interest (expense) income, net....................... Loss on extinguishment of debt..................... Other income, net .......................................... Total Other (Expense) Income ............... Net Income (Loss) ................................................ Net loss attributable to noncontrolling interests.......................................................... 7,969 98,625 14,801 267,708 137,285 31,945 29,549 21,894 6,325 226,998 40,710 (11,141) (17,526) 2,136 (26,531) 14,179 — Net Income (Loss) attributable to partners ........... $ 14,179 $ 1,418 21,400 — 22,818 8,869 3,459 7,340 5,629 1,076 26,373 (3,555) 115 — 69 184 (3,371) — — — — — — 3,028 128 — 3,156 (3,156) (28) — — (28) (3,184) — (3,371) $ 2,123 (1,061) $ 9,387 120,025 14,801 290,526 146,154 35,404 39,917 27,651 7,401 256,527 33,999 (11,054) (17,526) 2,205 (26,375) 7,624 2,123 9,747 97 Period from November 13, 2012 to December 31, 2012 TEP Consolidate Trailblazer Pipeline Company LLC Consolidate Tallgrass Pony Express Pipeline, LLC TEP (As currently reported) (in thousands) Revenues: Natural gas liquids sales................................ $ 18,554 $ — $ — $ Natural gas sales............................................ Transportation services ................................. Processing and other revenues ...................... Total Revenues....................................... Operating Costs and Expenses: Cost of sales and transportation services ...... Operations and maintenance ......................... Depreciation and amortization ...................... General and administrative ........................... Taxes, other than income taxes ..................... Total Operating Costs and Expenses...... Operating Income (Loss)...................................... Other (Expense) Income: Interest (expense) income, net ...................... Other income, net .......................................... Total Other (Expense) Income............... Net Income (Loss) ................................................ Net loss attributable to noncontrolling interests ......................................................... Net Income (Loss) attributable to partners........... $ Formation of BNN Water Solutions, LLC 1,910 13,102 1,722 35,288 18,298 3,353 4,086 7,133 1,107 33,977 1,311 (3,201) 482 (2,719) (1,408) 416 2,868 — 3,284 752 568 985 1,673 170 4,148 (864) 22 10 32 (832) — — — — — — 378 — — 378 (378) — — — (378) — (1,408) $ — (832) $ 252 (126) $ 18,554 2,326 15,970 1,722 38,572 19,050 3,921 5,449 8,806 1,277 38,503 69 (3,179) 492 (2,687) (2,618) 252 (2,366) 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% membership interest in Water Solutions. As part of the transaction, GWSI was renamed BNN Redtail, LLC ("Redtail"), became a subsidiary of Water Solutions, and issued preferred equity interests to TEI. Among the assets contributed by BNN and the other parties to the transaction were the other 50% interest in Redtail and a 100% equity interest in Alpha Reclaim Technology, LLC ("Alpha"), a company which sources treated wastewater from municipalities in Texas. Alpha is wholly-owned by Redtail. Upon closing of the transaction, TEP obtained a controlling financial interest in Water Solutions and accordingly has accounted for the transaction as a step acquisition under ASC 805. On the acquisition date, TEP remeasured its previously held 50% equity interest in Redtail to its fair value of $11.9 million, recognized a gain of $9.4 million, and consolidated Water Solutions. The 20% equity interest in Water Solutions held by noncontrolling interests was recorded at its acquisition date fair value of $1.4 million. The fair values of the previously held equity interest and the noncontrolling interest were determined using a discounted cash flow analysis. These fair value measurements are based on significant inputs that are not observable in the market and thus represent fair value measurements categorized within Level 3 of the fair value hierarchy under ASC 820. 98 The following represents the fair value of assets acquired and liabilities assumed at May 13, 2014 (in thousands): Accounts receivable......................................................................................................................... $ Property, plant and equipment......................................................................................................... Intangible assets............................................................................................................................... Accounts payable and accrued liabilities ........................................................................................ Distribution payable ........................................................................................................................ Net identifiable assets acquired..................................................................................................... Goodwill .......................................................................................................................................... Net assets acquired........................................................................................................................ $ 790 4,100 8,200 (1) (134) (634) 12,322 8,573 20,895 (1) The $8.2 million intangible asset acquired represents a major customer contract. See Note 8 – Goodwill and Other Intangible Assets for additional information. At December 31, 2014, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. 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 $5.0 million and $0.3 million, respectively, was recognized in the accompanying Consolidated Statements of Income for the period from May 13, 2014 to December 31, 2014. Pro Forma revenue and net income attributable to TEP for the year ended December 31, 2014 was $374.4 million and $61.7 million, respectively. No pro forma information is presented for the year ended December 31, 2013 or the periods from November 13, 2012 to December 31, 2012 or January 1, 2012 to November 12, 2012 as Water Solutions did not begin commercial operations until the first quarter of 2014. This unaudited pro forma financial information for TEP is presented as if the acquisition of Water Solutions had been completed on January 1, 2012. The pro forma financial information is not necessarily indicative of what the actual results of operations or financial position of TEP would have been if the transactions had in fact occurred on the date or for the period indicated, nor do they purport to project the results of operations or financial position of TEP for any future periods or as of any date. The pro forma financial information does not give effect to any cost savings, operating synergies, or revenue enhancements expected to result from the transactions or the costs to achieve these cost savings, operating synergies, and revenue enhancements. The pro forma revenue and net income includes adjustments for the year ended December 31, 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% 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. 5. Related Party Transactions TEP has no employees. TEP Pre-Predecessor Parent historically provided and charged TEP Pre-Predecessor 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. Beginning November 13, 2012, TD similarly provided and charged TEP for direct and indirect costs of services. TEP and TEP Pre-Predecessor record these costs on the accrual basis in the period in which TEP Pre-Predecessor Parent (or TD, beginning November 13, 2012) incurs them. Each of the wholly-owned companies comprising TEP and TEP Pre-Predecessor had agency arrangements with TEP Pre-Predecessor Parent or its affiliates (prior to November 13, 2012) and TD (beginning November 13, 2012) under which TEP Pre-Predecessor Parent, or its contractually obligated affiliate, or TD, as applicable, pay costs and expenses incurred by TEP and TEP Pre-Predecessor, act as agents for TEP and TEP Pre-Predecessor, and are reimbursed by TEP and TEP Pre-Predecessor for such payments. While the substance of the operating agreement remains the same, the cost structure under new management has changed, which affected the basis of certain allocations when the agreements transitioned from TEP Pre-Predecessor Parent to TD. 99 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 fourth quarter of 2014, TEP’s cost reimbursements to TD for costs discussed above were $5.3 million. In addition, the quarterly reimbursement from Pony Express to TD for the fourth quarter of 2014 was $4.6 million. 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 fourth quarter of 2014. 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, prior to April 1, 2014 for Trailblazer, and prior to September 1, 2014 for Pony Express. Balances lent to TD under the Pony Express cash management agreement effective September 1, 2014 are classified as related party receivables on the consolidated balance sheet and will be cash settled. TEP recognized interest income from TD of $1.5 million during the year ended December 31, 2014 on the receivable balance under the Pony Express cash management agreement. Totals of transactions with affiliated companies are as follows: TEP TEP Pre-Predecessor Year Ended December 31, 2014 Year Ended December 31, 2013 Period from November 13 to December 31, 2012 (in thousands) Period from January 1 to November 12, 2012 (in thousands) Cost of sales and transportation services ............ $ Charges to TEP and TEP Pre-Predecessor: (1) — $ — $ — $ 155 Property, plant and equipment, net.............. $ Other deferred charges................................. $ Operation and maintenance ......................... $ General and administrative (2)...................... $ 17,936 27 18,783 23,475 $ $ $ $ 7,604 799 18,439 20,140 $ $ $ $ 193 56 2,933 6,888 $ $ $ $ 1,052 130 12,874 7,960 Property, plant and equipment sales to: Kinder Morgan Energy Partners, LP ........... $ — $ — $ — $ 1,948 (1) Charges to TEP and TEP Pre-Predecessor include directly charged wages and salaries, other compensation and benefits, and shared services. (2) During the years ended December 31, 2014 and 2013, TEP reimbursed TD for general and administrative expenses as discussed above, resulting in allocated amounts for general and administrative costs. Details of balances with affiliates included in "Accounts receivable from related party" and "Accounts payable to related parties" in the Consolidated Balance Sheets are as follows: December 31, 2014 December 31, 2013 (in thousands) Receivable from related party: Tallgrass Operations, LLC ................................................................................... $ Total receivable from related party ............................................................... $ Accounts payable to related parties: Tallgrass Operations, LLC ................................................................................... $ Rockies Express Pipeline LLC............................................................................. Total accounts payable to related parties ...................................................... $ 73,393 73,393 3,894 21 3,915 $ $ $ $ — — 7,106 31 7,137 100 Balances of gas imbalances with affiliated shippers are as follows: Affiliate gas balance receivables ................................................................................. $ Affiliate gas balance payables ..................................................................................... $ (in thousands) 275 455 $ $ 137 122 December 31, 2014 December 31, 2013 Pursuant to the terms of a Purchase and Sale Agreement dated August 1, 2012, TD, through August 31, 2014, reimbursed TIGT for all costs TIGT incurred with respect to the Pony Express Abandonment, as defined in Note 16 – 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 433 miles of natural gas pipeline, and associated rights of way and certain other equipment, to Pony Express in 2013. For more information, see Note 16 – Regulatory Matters. Any costs incurred by TIGT subsequent to August 31, 2014 are reimbursed directly by Pony Express. TIGT’s expenditures for the Replacement Gas Facilities are captured in "Prepayments and other current assets" in the Consolidated Balance Sheets as they are incurred and interest is accrued until reimbursement takes place (which is typically monthly). During the year ended December 31, 2014 we received proceeds from TD of $69.2 million and incurred expenditures of $41.7 million. We recognized a contribution of $27.5 million from TD in our Consolidated Statement of Partners' Capital which represents the difference between the carrying amount of the Replacement Gas Facilities and the proceeds received from TD. At December 31, 2014, TEP had not incurred any expenditures for the Replacement Gas Facilities that had not been reimbursed. During the year ended December 31, 2013, reimbursements of $4.3 million related to expenditures prior to the closing of the IPO on May 17, 2013 were settled as equity distributions with TD. During the year ended December 31, 2013, reimbursements of $30.4 million related to expenditures subsequent to the closing of the IPO on May 17, 2013 were cash settled by 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. 6. Inventory The components of inventory at December 31, 2014 and December 31, 2013 consisted of the following: Gas in underground storage .................................................................... $ Materials and supplies............................................................................. Crude oil.................................................................................................. Natural gas liquids .................................................................................. Total inventory................................................................................. $ December 31, 2014 December 31, 2013 (in thousands) 8,896 3,049 581 519 13,045 $ $ 2,403 2,137 — 1,009 5,549 In July 2014, Pony Express entered into an agreement with Shell Trading (US) Company ("Shell") for the purchase of 800,000 barrels of crude oil that was available for initial line fill on the Pony Express System, which was subsequently sold back to Shell in November 2014. To support the resale obligation of Pony Express, in July 2014 TD paid Shell a deposit of $20 million and issued a letter of credit for $20 million and a parent guarantee of $40 million to Shell on behalf of Pony Express. TEP returned the barrels to Shell in November 2014. At that time, Shell returned the $20 million deposit to Pony Express, which Pony Express subsequently returned to TD. 101 7. Property, Plant and Equipment A summary of net property, plant and equipment by classification is as follows: Crude oil pipelines .................................................................................. $ Natural gas pipelines ............................................................................... Processing and treating assets ................................................................. General and other .................................................................................... Construction work in progress ................................................................ Accumulated depreciation and amortization........................................... Total property, plant and equipment, net.......................................... $ December 31, 2014 December 31, 2013 (in thousands) 939,536 $ 548,482 241,671 42,719 139,873 (59,200) 1,853,081 $ — 397,287 209,329 26,076 506,378 (22,264) 1,116,806 Depreciation expense was approximately $40.9 million for the year ended December 31, 2014, $36.6 million for the year ended December 31, 2013, $4.9 million for the period from November 13, 2012 to December 31, 2012, and $19.9 million for the period from January 1, 2012 to November 12, 2012. Capitalized interest was approximately $1.2 million for the year ended December 31, 2014, $867,000 for the year ended December 31, 2013, $15,000 for the period from November 13, 2012 to December 31, 2012 and $9,000 for the period from January 1, 2012 to November 12, 2012. Under lease agreements effective November 13, 2012, TIGT, as lessor, leases a portion of its office space to a third party. Rental income for the year ended December 31, 2014, the year ended December 31, 2013, and the period from November 13, 2012 to December 31, 2012 was approximately $1.0 million, $1.0 million, and $145,000, respectively, and was recorded as "Other income, net" in the accompanying Consolidated Statements of Income. As of December 31, 2014, future minimum rental income under non-cancelable operating leases as the lessor were as follows (in thousands): Year 2015...................................................................................... $ Total 2016...................................................................................... 2017...................................................................................... 2018...................................................................................... 2019...................................................................................... Thereafter ............................................................................. 828 772 787 802 817 205 Total...................................................................................... $ 4,211 8. Goodwill and Other Intangible Assets Reconciliation of Goodwill The following table presents a reconciliation of the carrying amount of goodwill by reportable segment for the reporting period: Year Ended December 31, 2014 Year Ended December 31, 2013 Natural Gas Transportation & Logistics Processing & Logistics (in thousands) Natural Gas Transportation & Logistics Total Processing & Logistics (in thousands) Total Balance at beginning of period $ Goodwill acquired.................... Balance at end of period .......... $ 255,558 — 255,558 $ $ 79,157 8,573 (1) 87,730 $ 334,715 8,573 $ 343,288 $ $ 255,558 — 255,558 $ $ 79,157 — 79,157 $ $ 334,715 — 334,715 (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. 102 Annual Goodwill Impairment Analysis TEP did not elect to apply the qualitative assessment option during our 2014 annual goodwill impairment testing, instead we proceeded directly to the two-step quantitative test. In Step 1 of the two-step quantitative test, we compared the fair value of each reporting unit with its respective book value, including goodwill, by using an income approach based on a discounted cash flow analysis. For the purposes of goodwill impairment testing, goodwill was allocated to our reporting units based on the enterprise value of each reporting unit at the date of acquisition. The fair value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and included a sensitivity analysis of the impact of changes in various assumptions. This approach required us to make long-term forecasts of future operating results and various other assumptions and estimates, the most significant of which are gross margin, operating expenses, general and administrative expenses, long-term growth rates and the weighted average cost of capital. The fair value of the reporting units was determined using significant unobservable inputs, considered Level 3 under the fair value hierarchy in the Codification. For each reporting unit, the results of the Step 1 impairment analysis indicated no potential impairment as the fair value of the reporting units was greater than their respective book values. As a result, in accordance with the Codification guidance, Step 2 of the impairment analysis was not necessary as part of the annual impairment analysis in 2014. Unpredictable events or deteriorating market or operating conditions could result in a future change to the discounted cash flow models and cause impairments in the future. We continue to monitor potential impairment indicators to determine if a triggering event occurs and will perform additional goodwill impairment analysis as necessary. Other Intangible Assets A summary of amortized intangible assets is as follows: December 31, 2014 December 31, 2013 Pony Express oil conversion use rights .................................... $ Redtail customer contract ......................................................... Accumulated amortization........................................................ Intangible assets, net............................................................ $ (in thousands) 105,973 $ 8,200 (9,635) 104,538 $ 105,973 — (3,406) 102,567 Amortization of intangible assets was approximately $6.2 million for the year ended December 31, 2014, $3.0 million for the year ended December 31, 2013, and $0.4 million for the period from November 13, 2012 to December 31, 2012. There was no amortization for the period from January 1, 2012 to November 12, 2012. Estimated future amortization for these intangible assets is as follows (in thousands): Year 2015...................................................................................... $ 2016...................................................................................... 2017...................................................................................... 2018...................................................................................... 2019...................................................................................... Thereafter ............................................................................. Total...................................................................................... $ Total 8,026 3,028 3,028 3,028 3,028 84,400 104,538 9. Risk Management TEP and TEP Pre-Predecessor may enter into derivative contracts with third parties for the purpose of hedging exposures that accompany their normal business activities. TEP and TEP Pre-Predecessor’s normal business activities directly and indirectly expose them to risks associated with changes in the market price of crude oil and natural gas, among other commodities. 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. Prior to November 13, 2012, TEP Pre-Predecessor applied hedge accounting to these derivative contracts. As discussed below, TEP elected not to apply hedge accounting. 103 Beginning on November 13, 2012, all previously hedge-designated derivative contracts were de-designated and changes in the fair value of all derivative contracts are now recorded in earnings in the period in which the change occurs. Accumulated other comprehensive income associated with the derivative contracts was immaterial as of the de-designation date and was eliminated in purchase accounting. During the period January 1, 2012 to November 12, 2012, the TEP Pre-Predecessor recognized no gain or loss on derivatives associated with the ineffectiveness of these hedges and did not exclude any component of the derivative contracts’ gain or loss from the assessment of hedge effectiveness. Under hedge accounting, as the hedged sales and purchases took place and TEP Pre-Predecessor recorded them into earnings in the same period, the TEP Pre-Predecessor also reclassified the associated gains and losses included in accumulated other comprehensive income into earnings. During the period January 1, 2012 to November 12, 2012, no gain or loss was reclassified into earnings as a result of the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period. Fair Value of Derivative Contracts The following table summarizes the fair values of TEP’s derivative contracts included in the accompanying Consolidated Balance Sheets: Energy commodity derivative contracts......................... Current liabilities $ (in thousands) — $ 184 Balance Sheet Location December 31, 2014 December 31, 2013 TEP had no derivative contracts outstanding as of December 31, 2014. As of December 31, 2013 we had no derivative contracts in asset positions. 104 Effect of Derivative Contracts on the Income Statement The following tables summarize the impact of derivative contracts for the years ended December 31, 2014 and 2013, the period from November 13, 2012 to December 31, 2012, and the period from January 1, 2012 to November 12, 2012: Derivatives in cash flow hedging relationships: Energy commodity derivative contracts....... Amount of gain (loss) recognized in OCI on derivatives (effective portion) TEP Year Ended December 31, 2014 Year Ended December 31, 2013 (in thousands) Period from November 13 to December 31, 2012 TEP Pre- Predecessor Period from January 1 to November 12, 2012 (in thousands) $ — $ — $ — $ 1,024 Amount of gain (loss) reclassified from Accumulated OCI into income (effective portion) TEP Location of gain (loss) reclassified from AOCI into income (effective portion) Year Ended December 31, 2014 Year Ended December 31, 2013 (in thousands) Period from November 13 to December 31, 2012 TEP Pre- Predecessor Period from January 1 to November 12, 2012 (in thousands) Derivatives in cash flow hedging relationships: Energy commodity derivative contracts....... Natural gas sales $ — $ — $ — $ 4,187 Amount of gain (loss) recognized in income on derivatives TEP Location of gain (loss) recognized in income on derivatives Year Ended December 31, 2014 Year Ended December 31, 2013 Period from November 13 to December 31, 2012 (in thousands) TEP Pre- Predecessor Period from January 1 to November 12, 2012 (in thousands) Derivatives not designated as hedging contracts: Energy commodity derivative contracts....... Natural gas sales $ (410) $ (548) $ 416 $ — 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 December 31, 2014, TEP had no derivative contracts outstanding, resulting in no credit exposure from TEP’s counterparties as of that date. 105 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 December 31, 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. When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used. The following table summarizes the fair value measurements of TEP’s energy commodity derivative contracts as of December 31, 2013 based on the fair value hierarchy established by the Codification: Liability fair value measurements using Quoted prices in active markets for identical assets (Level 1) Significant other observable inputs (Level 2) Significant unobservable inputs (Level 3) (in thousands) Total TEP as of December 31, 2013 Energy commodity derivative contracts........ $ 184 $ — $ 184 $ — 10. Long-term Debt Revolving Credit Facility On May 17, 2013, in connection with the IPO, TEP entered into 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. The Amendment modified 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 from $40 million to $60 million, (iii) increase the sublimit for letters of credit from $50 million 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%. 106 The following table sets forth the outstanding borrowings, letters of credit issued, and available borrowing capacity under the revolving credit facility as of December 31, 2014 and December 31, 2013: Total capacity under the revolving credit facility .................................... $ Less: Outstanding borrowings under the revolving credit facility...... Less: Letters of credit issued under the revolving credit facility ........ Available capacity under the revolving credit facility............................. $ December 31, 2014 December 31, 2013 (in thousands) 850,000 (559,000) — 291,000 $ $ 500,000 (135,000) (654) 364,346 The revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict TEP’s ability (as well as the ability of TEP’s restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions (including distributions from available cash, if a default or event of default under the credit agreement then exists or would result from making such a distribution), change the nature of TEP’s business, engage in certain mergers or make certain investments and acquisitions, enter into non-arms-length transactions with affiliates and designate certain subsidiaries as "Unrestricted Subsidiaries." In addition, TEP is required to maintain a consolidated leverage ratio of not more than 4.75 to 1.00 (which will be increased to 5.25 to 1.00 for certain measurement periods following the consummation of certain acquisitions) and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of December 31, 2014, TEP is in compliance with the covenants required under the revolving credit facility. The unused portion of the revolving credit facility is subject to a commitment fee, which 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 December 31, 2014, the weighted average interest rate on outstanding borrowings was 2.45%. 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 Consolidated Balance Sheets as of December 31, 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 December 31, 2014 ...... $ December 31, 2013 ...... $ — $ — $ (in thousands) 559,000 135,000 $ $ — $ — $ 559,000 135,000 $ $ 559,000 135,000 The long-term debt borrowed under the revolving credit facility is carried at amortized cost. As of December 31, 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 December 31, 2014. 107 11. Partnership Equity and Distributions Equity Distribution Agreement On October 31, 2014, we entered into an equity distribution agreement pursuant to which we may sell from time to time through a group of managers, as our sales agents, common units representing limited partner interests having an aggregate offering price of up to $200 million. Sales of the common units, if any, will be made by means of ordinary brokers’ transactions, to or through a market maker or directly on or through an electronic communication network, a "dark pool" or any similar market venue, or as otherwise agreed by the Partnership and one or more of the managers. We intend to use the net proceeds from any sale of the units for general partnership purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt. As of December 31, 2014, TEP had issued and sold 28,625 common units with a weighted average sales price of $44.20 per unit under our equity distribution agreement for net proceeds of approximately $1.1 million (net of approximately $215,000 in commissions and professional service expenses). We used the net proceeds for general partnership purposes. At December 31, 2014, approximately $198.7 million in aggregate offering price remained available to be issued and sold under the equity distribution agreement. July 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 $319.3 million after deducting the underwriter's discount and offering expenses paid by TEP. TEP used the net proceeds from the offering to fund a portion of the consideration for the acquisition of a 33.3% membership interest in Pony Express as discussed in Note 4 – Acquisitions. Issuance of Common Units to TD As discussed in Note 1 – Description of Business, TD completed the acquisition of TEP Pre-Predecessor subsidiary entities on November 13, 2012. On May 17, 2013, in conjunction with the closing of TEP’s IPO, TD’s ownership interest in TIGT and TMID was contributed to TEP in exchange for 9,700,000 common and 16,200,000 subordinated units (and other consideration consisting of debt assumption and cash distribution as more fully described above in Note 1 –Description of Business). Additionally, in 2014 TEP issued 385,140 common units to TD as partial consideration for the acquisition of Traiblazer and issued 70,340 common units to TD as partial consideration for the acquisition of a 33.3% membership interest in Pony Express. Distributions to Holders of Common Units, Subordinated Units and General Partner Units 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. 108 The following table shows the distributions for the years ended December 31, 2014 and 2013: Three Months Ended Date Paid Limited Partners Common and Subordinated Units Distributions General Partner Incentive Distribution Rights General Partner Units Total Distributions per Limited Partner Unit (in thousands, except per unit amounts) December 31, 2014 ....... February 13, 2015 ......... $ 23,782 $ 4,039 $ September 30, 2014....... November 14, 2014....... June 30, 2014 ................ August 14, 2014 ............ March 31, 2014 ............. May 14, 2014 ................ December 31, 2013 ....... February 12, 2014 ......... September 30, 2013....... November 13, 2013....... June 30, 2013 ................ August 13, 2013 ............ March 31, 2013 ............. N/A................................ 20,092 18,596 13,288 12,757 12,049 5,759 N/A 1,208 758 126 63 — — N/A 473 363 330 274 262 245 118 N/A $ 28,294 $ 21,663 19,684 13,688 13,082 12,294 5,877 N/A 0.4850 0.4100 0.3800 0.3250 0.3150 0.2975 0.1422 (1) N/A (1) 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 and June 30, 2013. Subordinated Units As of December 31, 2014, all subordinated units were currently held by TD. Under the terms of TEP's partnership agreement and upon the payment of the quarterly cash distribution to unitholders on February 13, 2015, the subordination period ended. As a result, the 16,200,000 subordinated units held by TD converted into common units on a one for one basis on February 17, 2015. The conversion of the subordinated units did not impact the aggregate amount of cash distributions paid. General Partner Units As of December 31, 2014, the general partner owns an approximate 1.7% general partner interest in TEP, which was represented by 834,391 general partner units. Under TEP’s partnership agreement, the general partner may at any time (but is under no obligation to) contribute additional capital to TEP in order to maintain its 2% general partner interest. As discussed in Note 4 – Acquisitions, 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 maintain its 2% general partner interest. TEP subsequently issued additional units in July 2014 and September 2014 to fund a portion of the consideration and as consideration for the acquisition of Pony Express, respectively. The general partner did not contribute additional capital to maintain its 2% general partner interest at the time of either issuance. Incentive Distribution Rights 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. The following discussion related to incentive distributions assumes that TEP’s general partner maintains its 2% 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"); 109 • • • 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, or 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 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 Contributions and Distributions During the year ended December 31, 2014, TEP received net contributions of $312.1 million, $27.5 million, and $5.4 million from the Predecessor Member, TD, and noncontrolling interests, respectively. Net contributions of $312.1 million from the Predecessor Member is composed of net contributions of $612.1 million relating to the cash management agreements with TD, as well as a cash distribution of $300 million of the proceeds from the issuance of the preferred membership interest to TEP from Pony Express to TD pursuant to the Pony Express Contribution and Sale Agreement. As discussed in Note 2 – Summary of Significant Accounting Policies, prior to May 17, 2013 for TIGT and TMID, prior to April 1, 2014 for Trailblazer, and prior to September 1, 2014 for Pony Express, the net amount of transfers for loans made each day through the centralized cash management system with TD, less reimbursement payments under the agency agreement described in Note 5 – Related Party Transactions, was recognized as net equity contributions or distributions during that time period. There were no equity contributions or distributions made to TD subsequent to Trailblazer's acquisition by TEP on April 1, 2014 or the acquisition of Pony Express effective September 1, 2014. The $27.5 million contribution from TD represents the difference between the carrying amount of the Replacement Gas Facilities and the proceeds received from TD, as discussed in Note 5 – Related Party Transactions. The $5.4 million contribution from noncontrolling interests represents the cash contributed to Pony Express from TD to fund the quarterly preference payment to TEP as discussed in Note 4 – Acquisitions. During the year ended December 31, 2014, Pony Express made a distribution of $5.4 million to TD, which was settled via the Pony Express cash management agreement. During the year ended December 31, 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. Also during the year ended December 31, 2014, TEP was deemed to have made a capital distribution of $8.7 million to the general partner, which represents the excess purchase price, consisting of $27 million in cash and limited partner common units valued at $3.0 million issued directly to TD, over the net book value of the 1.9585% membership interest in Pony Express transferred from TD to TEP in accordance with the Pony Express Contribution and Sale Agreement. See Note 4 – Acquisitions for additional information regarding the Trailblazer and Pony Express acquisitions. During the year ended December 31, 2013, net distributions from TEP Predecessor to TD were approximately $118.5 million, and included the $85.5 million to TD related to the contribution of TIGT and TMID to TEP as well as the $31.2 million net proceeds from the exercise of the underwriter’s option to purchase additional common units as part of the IPO. During the year ended December 31, 2013, the Trailblazer Predecessor and Pony Express Predecessor recognized net contributions from TD of $379.9 million. There were no net distributions from TEP to TD for the period from November 13, 2012 to December 31, 2012. Net distributions from TEP Pre-Predecessor to its parent for the period from January 1, 2012 to November 12, 2012 were $57.7 million. 110 12. Commitments & Contingent Liabilities Leases Rent expense under operating leases and right of way agreements totaled approximately $4.7 million, $327,000, $43,000, and $206,000 for the year ended December 31, 2014, the year ended December 31, 2013, the period from November 13, 2012 to December 31, 2012 and the period from January 1, 2012 to November 12, 2012, respectively. At December 31, 2014, future minimum rental commitments under major, non-cancelable operating leases were as follows (in thousands): Year 2015...................................................................................... $ 2016...................................................................................... 2017...................................................................................... 2018...................................................................................... 2019...................................................................................... Thereafter ............................................................................. Total...................................................................................... $ Total 24,540 27,784 28,269 28,694 29,225 506,833 645,345 Operating lease agreements primarily consist of storage capacity leased by Pony Express from Deeprock Development, LLC ("Deeprock"), an unconsolidated affiliate of TD and Tallgrass Sterling Terminal, LLC ("Sterling"), an indirect wholly- owned subsidiary of TD. Pony Express entered into a lease agreement with Deeprock on November 7, 2012 for the use by Pony Express of storage capacity at the Deeprock tank storage facility near Cushing, Oklahoma. The lease has a five year term which commenced on October 7, 2014. Pony Express made upfront payments totaling $10.9 million, of which $4.6 million was paid in 2013 and $6.3 million was paid in 2014. The upfront payments are recorded as "Deferred charges and other assets" on the accompanying consolidated balance sheets and will be amortized over the lease term. Pony Express has the right to extend the term of the lease for additional periods of five or two years, not to exceed a total of 20 years from when the lease commences. Future minimum rental commitments above assume renewal of the Deeprock lease for the full 20 year term as the storage capacity at Deeprock is integral to the operations of the Pony Express System and renewal of the lease is reasonably assured as a result. On August 26, 2014, Pony Express entered into a lease agreement with Sterling for the use by Pony Express of storage capacity at the Sterling tank storage facility in northeast Colorado for a five year term beginning on the first day of the first month immediately following the day that the lateral on the Pony Express System located in Northeast Colorado is placed in service, which is expected to be in the first half of 2015. Pony Express has the right to extend the term of the lease for additional periods of five years, not to exceed a total of 20 years from the commencement of the lease agreement. Future minimum rental commitments above assume renewal of the Sterling lease for the full 20 year term as the storage capacity at Sterling is integral to the operations of the lateral in Northeast Colorado and renewal of the lease is reasonably assured as a result. Capital Expenditures Approximately $63.5 million had been committed for the future purchase of property, plant and equipment at December 31, 2014. 13. 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. 111 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 and Pony Express prior to its acquisition effective September 1, 2014 is allocated to predecessor operations in the table below. Historical earnings of transferred businesses for periods prior to the date of the common control drop-down transaction are solely those of the general partner and, therefore we have appropriately excluded any allocation to the limited partner units when determining net income available to common and subordinated unitholders. We present the financial results of any transferred business prior to the drop down transaction date in the line item "Predecessor operations interest in net (income) loss" in the table below. The following table illustrates the Partnership’s calculation of net income per common and subordinated unit for the years ended December 31, 2014 and 2013: Net income....................................................................... $ Net loss attributable to noncontrolling interests....... Net income attributable to partners ................................. Predecessor operations interest in net (income) loss....... General partner interest in net income............................. Net income available to common and subordinated unitholders ....................................................................... $ Basic net income per common and subordinated unit..... $ Diluted net income per common and subordinated unit.. $ Basic average number of common and subordinated units outstanding.............................................................. Equity Participation Unit equivalent units ...................... Diluted average number of common and subordinated units outstanding.............................................................. Year Ended December 31, 2014 Year Ended December 31, 2013 Period from January 1, 2013 to May 16, 2013 Period from May 17, 2013 to December 31, 2013 (in thousands, except per unit amounts) 59,329 $ 7,624 $ 5,049 $ 2,123 9,747 4,432 (7,188) 761 5,810 1,172 (6,982) 6,991 $ — $ $ $ 0.17 0.17 40,450 1,008 41,458 11,352 70,681 (1,508) (7,399) 61,774 1.39 1.36 44,346 1,048 45,394 $ $ $ 112 2,575 1,362 3,937 3,260 (206) 6,991 0.17 0.17 40,450 1,008 41,458 14. Major Customers and Concentration of Credit Risk During the year ended December 31, 2014, the year ended December 31, 2013 and the period from November 13, 2012 to December 31, 2012, one non-affiliated customer, Phillips 66, accounted for $113.6 million (31%), $102.0 million (35%) and $11.2 million (29%) of TEP’s total operating revenues, respectively. During the period from January 1, 2012 to November 12, 2012, the same non-affiliated customer accounted for $68.9 million (31%) of TEP Pre-Predecessor’s total operating revenues. Phillips 66 was previously a part of ConocoPhillips and began trading separately on the New York Stock Exchange starting May 1, 2012. All of these revenues were earned in our Processing & Logistics segment. For the year ended December 31, 2014, the percentage of segment revenues from the top ten non-affiliated customers for each segment was as follows: Natural Gas Transportation & Logistics ........................... Crude Oil Transportation & Logistics............................... Processing & Logistics...................................................... 48% 94% 92% Percentage of Segment Revenue TEP mitigates credit risk by requiring collateral or financial guarantees and letters of credit from customers with specific credit concerns. In support of credit extended to certain customers, TEP had received prepayments of $3.1 million and $3.8 million at December 31, 2014 and 2013, respectively, included in the caption "Other current liabilities" in the accompanying Consolidated Balance Sheets. 15. 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. 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. Vesting of the EPUs granted to employees is contingent upon the Pony Express System being placed into service and will generally occur in two parts, with one-third vesting on the later of the Pony Express System in-service date or May 13, 2015, and the remaining two-thirds vesting on the later of the Pony Express System in-service date or May 13, 2017. The Pony Express System was placed in service in October 2014. New EPUs granted after the first quarter of 2014 will vest on terms and conditions as approved by the general partner or the plan administrator. 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 $10.2 million was recognized during the year ended December 31, 2014. Of the total compensation cost, $5.1 million was recognized as compensation expense at TEP for the year ended December 31, 2014 and the remainder was allocated to TD. Total equity-based compensation cost related to the EPU grants of approximately $4.2 million was recognized during the year ended December 31, 2013. Of the total compensation cost, $1.8 million was recognized 113 as compensation expense at TEP for the year ended December 31, 2013 and the remainder was allocated to TD. As of December 31, 2014, $13.2 million of total compensation cost related to non-vested EPUs is expected to be recognized over a weighted average period of 2.1 years, a portion of which will be charged to TD. The following table summarizes the changes in the EPUs outstanding for the years ended December 31, 2014 and 2013: Year Ended December 31, 2014 Year Ended December 31, 2013 Equity Participation Units Weighted Average Grant Date Fair Value Equity Participation Units Weighted Average Grant Date Fair Value Beginning of period ........................ 1,474,250 $ Granted..................................... Forfeited................................... 147,500 (96,000) End of period................................... 1,525,750 $ 17.54 30.23 17.83 18.75 — $ 1,515,000 (40,750) 1,474,250 $ — 17.54 (17.49) 17.54 16. 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 433 miles of mainline natural gas pipeline facilities, along with associated rights of way and other related equipment (collectively, the "Pony Express Assets"), and the natural gas service therefrom, by transferring those assets to Pony Express, which 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 while at the same time continuing to operate TIGT’s natural gas transportation facilities to meet all current and expected needs of its natural gas customers. By a FERC order issued September 12, 2013, TIGT was granted authorization to abandon the Pony Express Assets and construct the Replacement Gas Facilities. On October 7, 2013 TIGT commenced the mobilization of personnel and equipment for the construction of the Replacement Gas Facilities necessary to complete the Pony Express Abandonment to continue service to existing TIGT customers. In December 2013, TIGT removed the Pony Express Assets from gas service and sold those assets to Pony Express. On May 1, 2014, TIGT commenced commercial service through all of the Replacement Gas Facilities, with the exception of Units 3 and 4 at the Tescott Compressor Station. Service through Units 3 and 4 at the Tescott Compressor Station commenced on May 30, 2014. Trailblazer 2013 Rate Case Filing - Docket No. RP13-1031 On July 1, 2013, Trailblazer made a rate filing with 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, 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. 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 114 case at FERC. Trailblazer filed a motion with 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, FERC approved the Stipulation and Agreement. On June 30, 2014, Trailblazer filed tariff sheets to implement the Stipulation and Agreement effective July 1, 2014. Estimated refunds were reserved from revenues recorded in January 2014. On July 1, 2014, Trailblazer submitted refunds to its customers for amounts collected in excess of amounts that would have been collected under the Settlement Rates, with interest, and on July 18, 2014, filed a report of refunds with the FERC. The FERC issued orders accepting the tariff sheets with the requested effective date of July 1, 2014 and accepting the refund report filing on July 25, 2014 and August 7, 2014, respectively. Pony Express In anticipation of placing the Pony Express System into service, several petitions for declaratory orders were submitted to the FERC by Pony Express, its predecessor Kinder Morgan Pony Express Pipeline LLC, and certain upstream pipelines interconnected with the Pony Express System to address considerations related to the Pony Express System and other matters. In response to these petitions, the FERC issued three declaratory orders (two in 2012 and one in 2014) approving the proposed rate structures and terms of service for the Pony Express System. On September 19, 2014 Pony Express filed with the FERC to adopt a tariff for initial local Non Contract Rates as well as an initial Rules and Regulations in accordance with the Interstate Commerce Act to be effective starting on October 1, 2014. Local Contract Tariff rates were filed with the FERC on October 29, 2014 to be effective starting November 1, 2014. Joint Contract Tariff rates for oil received into the Pony Express pipeline system from the Belle Fourche Pipeline were filed on October 16, 2014 to be effective starting November 1, 2014. Hiland Pipeline Company has not yet filed the Joint Contract Tariff rates for movements between its system and the Pony Express System. Other Regulatory Matters There are currently no proceedings challenging the rates of Pony Express, TIGT, or Trailblazer. Regulators, as well as shippers, do have rights, under circumstances prescribed by applicable regulations, to challenge the rates that TIGT and Trailblazer charge. Further, the statute governing service by Pony Express allows parties having standing to file complaints in regard to existing tariff rates and provisions. If the complaint is not resolved, the FERC may conduct a hearing and order a crude oil pipeline to make reparations going back for up to two years prior to the date on which a complaint was filed if a rate is found to be unjust and unreasonable. TEP can provide no assurance that current rates will remain unchallenged. Any successful challenge could have a material, adverse effect on TEP’s future earnings and cash flows. 17. 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, had aggregate reserves for legal claims of approximately $0.6 million and $0.3 million as of December 31, 2014 and 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. The matter was removed to the US District Court for the District of Kansas. 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. 115 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 has since placed this line into oil service and restored pressure to full maximum allowable operating pressure. TEP is currently working with PHMSA to develop a plan to close the Corrective Action Order received from PHMSA regarding the Goshen County failure and is evaluating the cost of anticipated remediation activities. On August 31, 2014, a leak occurred at the Sterling Pump Station on the Pony Express System in Logan County, Colorado, which resulted in a release of approximately 200 bbls of crude oil. The spill was entirely contained on TEP property. We have presented our incident investigation findings to PHMSA and are currently working with PHMSA on the matter. On October 7, 2014 an overpressure event occurred upstream of the Lincoln Pump Station, which resulted in an overflow of the sump at the Lincoln Pump Station. On October 28, 2014, an overpressure situation occurred at the Cushing Terminal in Payne County, Oklahoma. On November 17, 2014, a leak occurred at the Sterling Pig Adapter on the Pony Express System in Logan County, Colorado due to a one-inch valve that was left in a partial open state. This incident resulted in a spill of approximately 119 bbls of crude oil. We have presented our incident investigation findings to PHMSA and are currently working with PHMSA on the matter. TEP is currently evaluating the cost of anticipated remediation activities. 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 had environmental accruals of $5.3 million and $5.0 million at December 31, 2014 and 2013, respectively. TMID Casper Plant, U.S. EPA Notice of Violation In August 2011, the U.S. EPA and the Wyoming Department of Environmental Quality ("WDEQ") conducted an inspection of the Leak Detection and Repair ("LDAR") Program at the Casper Gas Plant in Wyoming. In September 2011, TMID received a letter from the U.S. EPA alleging violations of the Standards of Performance of Equipment Leaks for Onshore Natural Gas Processing Plant requirements under the Clean Air Act. TMID received a letter from the U.S. EPA concerning settlement of this matter in April 2013 and received additional settlement communications from the U.S. EPA and Department of Justice beginning in July 2014. Settlement negotiations are continuing, including attempted resolution of more recently identified LDAR issues. 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. Casper Gas Plant On November 25, 2014, WDEQ issued a Notice of Violation for violations of Part 60 Subpart OOOO related to the Depropanizer project (wv-14388, issued 7/9/13) in Docket No. 5506-14. TMID had discussed the issues in a meeting with WDEQ in Cheyenne on November 17, 2014, and submitted a disclosure on November 20, 2014 detailing the regulatory issues and potential violations. The project triggered a modification of Subpart OOOO for the entire plant. The project equipment as well as plant equipment subjected to Subpart OOOO was not monitored timely, and initial notification was not made timely. Settlement negotiations with WDEQ are currently ongoing. 18. Reporting Segments TEP’s operations are located in the United States. During the third quarter of 2014, management revised TEP's segment reporting structure to reflect the acquisition of a membership interest in Pony Express. As a result, TEP is now organized into three reporting segments: (1) Natural Gas Transportation & Logistics, (2) Crude Oil Transportation & Logistics, and (3) Processing & Logistics. 116 Natural Gas Transportation & Logistics The Natural Gas Transportation & Logistics segment is engaged in ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities that provide services to on-system customers (such as third- party LDCs), industrial users and other shippers. As discussed in Note 2 – Summary of Significant Accounting Policies, results for prior periods have been recast to reflect the operations of Trailblazer. Crude Oil Transportation & Logistics The Crude Oil Transportation & Logistics segment is engaged in ownership and construction of a FERC-regulated crude oil pipeline to serve the Bakken Shale and other nearby oil producing basins. The Pony Express System was placed in service in October 2014. The Crude Oil Transportation & Logistics segment also includes the construction of a lateral pipeline in Northeast Colorado, which will interconnect with the Pony Express System just east of Sterling, Colorado and is expected to be placed in service during the first half of 2015. As discussed in Note 2 – Summary of Significant Accounting Policies, results for prior periods have been recast to reflect the operations of Pony Express. Processing & Logistics The Processing & Logistics segment is engaged in ownership and operation of natural gas processing, treating and fractionation facilities that produce NGLs and residue gas that is sold in local wholesale markets or delivered into pipelines for transportation to additional end markets, as well as water business services provided primarily to the oil and gas exploration and production industry. Corporate and Other Corporate and Other includes corporate overhead costs 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. The following tables set forth TEP’s segment information for the periods indicated: TEP Year Ended December 31, 2014 Year Ended December 31, 2013 Total Revenue Inter- Segment (in thousands) External Revenue Total Revenue Inter- Segment (in thousands) External Revenue Natural Gas Transportation & Logistics ................................... $ Crude Oil Transportation & Logistics ................................... Processing & Logistics............. Corporate and other .................. Total revenue............................ $ 140,080 $ (5,257) $ 134,823 $ 127,877 $ (1,920) $ 125,957 28,343 208,390 — — — — 28,343 208,390 — — 164,569 — 376,813 $ (5,257) $ 371,556 $ 292,446 $ — — — (1,920) $ — 164,569 — 290,526 117 TEP TEP Pre-Predecessor Period from November 13 to December 31, 2012 Period from January 1 to November 12, 2012 Total Revenue Inter- Segment (in thousands) External Revenue Total Revenue Inter- Segment (in thousands) External Revenue Natural Gas Transportation & Logistics .................................. $ Crude Oil Transportation & Logistics .................................. Processing & Logistics ............ Corporate and other ................. Total revenue ........................... $ 16,696 $ (96) $ 16,600 $ 104,002 $ (696) $ 103,306 — 21,972 — — — — — 21,972 — — 116,986 — 38,668 $ (96) $ 38,572 $ 220,988 $ — — — (696) $ — 116,986 — 220,292 TEP Year Ended December 31, 2014 Year Ended December 31, 2013 Total Adjusted EBITDA Inter- Segment (in thousands) External Adjusted EBITDA Total Adjusted EBITDA Inter- Segment (in thousands) External Adjusted EBITDA 67,593 $ (4,015) $ 63,578 $ 56,821 $ (1,920) $ 54,901 (43) 23,192 (1,580) — 1,920 — 15,711 33,089 (2,500) — — — 15,711 33,089 (2,500) 7,648 45,389 — (184) 5,136 1,464 (717) (10,151) (9,388) (43) 25,112 (1,580) 11,035 37,898 17,526 386 1,798 — — — — $ 70,681 $ 9,747 Natural Gas Transportation & Logistics ................................... $ Crude Oil Transportation & Logistics ................................... Processing & Logistics............. Corporate and other .................. Reconciliation to Net Income: Interest expense, net ................. Depreciation and amortization expense, net of noncontrolling interest ...................................... Loss on extinguishment of debt ........................................... Non-cash (gain) loss related to derivative instruments .............. Non-cash compensation expense ..................................... Distributions from unconsolidated investment ....... Equity in earnings of unconsolidated investment ....... Non-cash loss allocated to noncontrolling interest.............. Gain on remeasurement of unconsolidated investment ....... Net income attributable to partners ..................................... 118 Natural Gas Transportation & Logistics .................................. $ Crude Oil Transportation & Logistics .................................. Processing & Logistics ............ Corporate and other ................. Reconciliation to Net Income: ................................... Interest expense, net ................ Depreciation and amortization expense, net of noncontrolling interest ..................................... Texas Margin Taxes................. Non-cash (gain) loss related to derivative instruments ............. Net (loss) income attributable to partners ................................ TEP TEP Pre-Predecessor Period from November 13 to December 31, 2012 Period from January 1 to November 12, 2012 Total Adjusted EBITDA Inter- Segment (in thousands) External Adjusted EBITDA Total Adjusted EBITDA Inter- Segment (in thousands) External Adjusted EBITDA 2,993 $ (96) $ 2,897 $ 52,459 $ (696) $ 51,763 — 2,744 — — 96 — — 18,302 — — 696 — — 2,840 — 3,179 5,197 — (273) — 18,998 — (1,661) 20,647 279 — $ (2,366) $ 51,496 Year Ended December 31, 2014 TEP Year Ended December 31, 2013 (in thousands) Period from November 13 to December 31, 2012 TEP Pre-Predecessor Period from January 1 to November 12, 2012 Natural Gas Transportation & Logistics....... $ Crude Oil Transportation & Logistics.......... Processing & Logistics................................. Corporate and other ...................................... Total capital expenditures............................. $ 20,580 $ 28,184 $ 9,205 $ 631,883 13,187 — 286,824 31,012 — — 3,493 — 665,650 $ 346,020 $ 12,698 $ 7,646 — 11,894 — 19,540 Natural Gas Transportation & Logistics................................................................. $ Crude Oil Transportation & Logistics.................................................................... Processing & Logistics........................................................................................... Corporate and other ................................................................................................ Total assets ............................................................................................................. $ December 31, 2014 December 31, 2013 (in thousands) 716,106 1,394,793 340,620 5,678 2,457,197 $ $ 734,145 566,156 326,599 4,513 1,631,413 119 19. Selected Quarterly Financial Data (Unaudited) The following tables summarize the unaudited quarterly statements operations for TEP for 2014 and 2013: TEP Quarter Ended 2014 First Second Third Fourth (in thousands, except per unit amounts) Total revenues ....................................................... $ Operating income .................................................. $ Net income ............................................................ $ Net income attributable to partners ....................... $ Net income allocable to limited partners .............. $ Basic net income per limited partner unit ............. $ Diluted net income per limited partner unit .......... $ 94,779 16,529 16,617 17,124 12,518 0.31 0.30 $ $ $ $ $ $ $ 77,320 6,475 14,728 15,286 15,771 0.39 0.38 $ $ $ $ $ $ $ 89,953 11,580 11,253 11,444 11,143 0.24 0.23 $ $ $ $ $ $ $ 109,504 18,829 16,731 26,827 22,342 0.46 0.45 TEP Quarter Ended 2013 First Second Third Fourth (in thousands, except per unit amounts) Total revenues ....................................................... $ Operating income .................................................. $ Net income (loss) .................................................. $ Net income (loss) attributable to partners ............. $ Net income allocable to limited partners .............. $ Basic net income per limited partner unit ............. $ Diluted net income per limited partner unit .......... $ 65,688 8,917 3,709 $ $ $ 4,215 $ — (1) $ — (1) $ — (1) $ 69,347 $ 68,718 $ $ 6,592 (13,984) (13,479) $ (13,365) (2) $ (0.33) (2) $ (0.33) (2) $ 5,401 5,095 5,600 6,866 0.17 0.17 $ $ $ $ $ $ $ 86,773 13,089 12,804 13,411 13,490 0.33 0.33 (1) No income was allocated to the limited partners until after the effective date of the IPO on May 17, 2013. (2) The second quarter of 2013 represented a prorated amount of net income allocated to the limited partners, based upon the number of days between the closing of the IPO on May 17, 2013 to June 30, 2013. 20. Subsequent Events GP Holdings Registration Statement On January 28, 2015, Tallgrass GP Holdings, LLC ("GP Holdings"), a privately held limited liability company that currently owns the general partners of TD and TEP, announced that it intends to file a registration statement with the SEC for an initial public offering of equity interests in a newly formed entity that is expected to own, directly or indirectly, all of TEP’s incentive distribution rights, TEP’s general partner interest, and a certain number of common units representing limited partner interests in TEP. Conversion of Subordinated Units The 16,200,000 subordinated units outstanding at December 31, 2014 were converted to common units on February 17, 2015 upon payment of the fourth quarter 2014 distribution on February 13, 2015. For additional information, see Note 11 – Partnership Equity and Distributions. 120 Potential Acquisition On January 8, 2015, TEP announced that TD offered TEP the right to purchase an additional 33.3% membership interest in Pony Express pursuant to the right of first offer in the Omnibus Agreement executed between TEP and TD in connection with TEP's initial public offering in May 2013. If consummated, this transaction would increase TEP’s membership interest in Pony Express to 66.7%. Terms of the offer have not been finalized. A Conflicts Committee of the board of directors of our general partner, consisting solely of independent directors, has been formed to evaluate the offer with assistance from external advisors to be engaged by the Conflicts Committee. No definitive transaction agreement has been executed at this time and the proposed transaction remains subject to review, negotiations and approval by the Conflicts Committee and by the board of directors of TEP’s general partner. In conjunction with the proposed transaction, the parties made required filings under the Hart-Scott- Rodino Antitrust Improvements Act and the waiting period for consummating the transaction has terminated. 121 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosures None. Item 9A. Controls and Procedures Evaluation of Disclosure Controls and Procedures As required by Rule 13a 15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a 15(e) and 15d 15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon their evaluation of those controls and procedures performed as of December 31, 2014, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective. Management’s Assessment of Internal Control over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed under the supervision of our principal executive officer and principal financial officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles. As of December 31, 2014, management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in the 1992 "Internal Control - Integrated Framework," issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment and those criteria, management determined that we maintained effective internal control over financial reporting as of December 31, 2014. Because of its inherent limitations, internal control over financial reporting may not prevent or detect fraud or misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Pursuant to 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. Changes in Internal Control over Financial Reporting During the quarter ended December 31, 2014, we implemented a new logistics, transaction accounting and commercial management system and internal controls for the Pony Express System. There have not been any 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 December 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Item 9B. Other Information None. 122 Item 10. Directors, Executive Officers and Corporate Governance PART III We are a limited partnership and, therefore, have no officers or directors. Unless otherwise indicated, references to our officers and directors in Items 10 through 14 of this Annual Report refer to the officers and directors of our general partner. Management of Tallgrass Energy Partners, LP Our general partner, Tallgrass MLP GP, LLC, manages our operations and activities on our behalf through its directors and officers. Our general partner is not elected by our unitholders and will not be subject to re-election in the future. Directors of our general partner oversee our operations. Tallgrass GP Holdings, LLC, which is owned and controlled by EMG, Kelso and certain members of our management team, is the sole owner of our general partner and has the right to appoint the entire board of directors of our general partner, including our independent directors. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly non-recourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are non-recourse to it. As of December 31, 2014, the board of directors of our general partner had nine directors, four of whom the board has determined meet the independence standards established by the NYSE and the Exchange Act. The four independent directors are Jeffrey A. Ball (for purposes of Audit Committee participation only), Terrance D. Towner, Roy N. Cook, and Jeffrey R. Armstrong. The NYSE does not require a publicly-traded limited partnership like ours to have a majority of independent directors on the board of directors of its general partner or to establish a compensation or a nominating and corporate governance committee. However, our general partner is required to have an audit committee of at least three members, and all of its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following the consummation of the IPO. As of December 31, 2014, the audit committee of the board of directors of our general partner had three members, each of whom meet the independence standards established by the NYSE and the Exchange Act. In evaluating director candidates, Tallgrass GP Holdings, LLC assesses whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties. All of the executive officers of the general partner of Tallgrass Development are also executive officers of our general partner and will devote such portion of their productive time to our business and affairs as is deemed reasonably required to manage and conduct our operations. Neither our general partner nor Tallgrass Development and its affiliates currently receive any management fee or other compensation in connection with the management or operation of our business. However, our partnership agreement requires us to reimburse our general partner and its affiliates for all expenses incurred and payments made on our behalf in connection with managing our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. In addition, the Omnibus Agreement requires us to reimburse Tallgrass Development’s general partner and its affiliates for expenses they incur in providing general and administrative services to us. Neither our partnership agreement nor the Omnibus Agreement limits the amount of expenses for which our general partner or Tallgrass Development’s general partner and its affiliates may be reimbursed. 123 Directors and Executive Officers of Our General Partner The following table shows information for the directors and executive officers of our general partner as of February 19, 2015. Name David G. Dehaemers, Jr. William R. Moler Gary J. Brauchle George E. Rider Richard L. Bullock Gary D. Watkins Frank J. Loverro Stanley de J. Osborne Jeffrey A. Ball John T. Raymond Terrance D. Towner Roy N. Cook Jeffrey R. Armstrong Age Position with Tallgrass MLP GP, LLC 54 49 41 61 60 President, Chief Executive Officer and Director Executive Vice President, Chief Operating Officer and Director Executive Vice President and Chief Financial Officer Executive Vice President, General Counsel and Secretary Vice President, Human Resources, Tax and Risk Management 42 Vice President and Chief Accounting Officer 46 44 40 44 56 57 45 Director Director Director Director Director Director Director Our directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers. David G. Dehaemers, Jr. has been a director and the President and Chief Executive Officer of our general partner since February 2013. Mr. Dehaemers has served as a director and the President and Chief Executive Officer of GP Holdings since February 2013 and as the President and Chief Executive Officer of Tallgrass Development and its general partner since August 2012. Prior to joining our general partner, Mr. Dehaemers served as Co-Founder, Chief Executive Officer and Chief Investment Officer of Tallgrass MLP Fund I, L.P., a private MLP Investment Fund from 2008 to 2012. Mr. Dehaemers also served as Executive Vice President of corporate development at Inergy, LP ("NRGY") from 2003 to 2007. Mr. Dehaemers played a role in NRGY’s corporate development group, where he focused on developing its long-term expansion strategies in the midstream area, which included acquisitions and expansion projects in excess of $500 million. Mr. Dehaemers also was an owner of Inergy Holdings, L.P. ("NRGP") when that entity went public in 2005. Before Inergy, Mr. Dehaemers was part of the executive management team of Kinder Morgan, Inc. and Kinder Morgan Energy Partners, LP from 1997 to 2003, where he served as the Chief Financial Officer from 1997 to 2000. In 2000, Mr. Dehaemers assumed responsibility for Kinder Morgan’s corporate development efforts, in which role he and his team developed and executed Kinder Morgan’s growth strategies. Mr. Dehaemers holds an undergraduate degree in Accounting from Creighton University in Omaha, Nebraska and is a Certified Public Accountant. He also holds a Juris Doctorate in Law from University of Missouri-Kansas City. We believe that Mr. Dehaemers’ education and experience, coupled with the leadership qualities demonstrated by his executive background, bring important experience and skill to the board of directors of our general partner. William R. Moler has been a director and Chief Operating Officer and Executive Vice President of our general partner since February 2013. Mr. Moler has also served as a director, Executive Vice President and Chief Operating Officer of GP Holdings since February 2013 and as Executive Vice President and Chief Operating Officer of Tallgrass Development and its general partner since October 2012. From 2004 until his departure in October 2012, Mr. Moler served in various capacities with Inergy, L.P. and its affiliates, most recently as Senior Vice President and Chief Operating Officer of Inergy Midstream, L.P. and President and Chief Operating Officer—Natural Gas Midstream Operations of Inergy, L.P. Prior to joining Inergy, L.P., Mr. Moler was with Westport Resources Corporation from 2002 to 2004, where he served as both General Manager of Marketing and Transportation Services and General Manager of Westport Field Services, LLC. Prior to Westport, Mr. Moler served in various leadership positions at Kinder Morgan, Inc. and its predecessors from 1988 to 2002. Mr. Moler earned a Bachelor of Science degree in Mechanical Engineering from Texas Tech University in 1988. We believe that as a result of his background and knowledge, as well as the attributes of leadership demonstrated by his executive experience, Mr. Moler brings substantial experience and skill to the board of directors of our general partner. 124 Gary J. Brauchle has been Executive Vice President and Chief Financial Officer of our general partner since February 2013 and has held the same positions for GP Holdings since February 2013 and for Tallgrass Development and its general partner since November 2012. Prior to joining Tallgrass, Mr. Brauchle was Vice President and Chief Accounting Officer at McDermott International, Inc., a global engineering and construction company serving the oil and gas industry during 2012 and as Corporate Controller from 2010 to 2012. He joined McDermott in 2003 and served in various positions of increasing responsibility, including as Director of Internal Audit from 2005 to 2007 and as Director of Operational Accounting and Assistant Controller for an operating subsidiary from 2007 to 2008 and 2008 to 2010, respectively. Mr. Brauchle also served in the Houston office of PricewaterhouseCoopers’ energy and utilities practice from 1997 to 2003, including as a Manager from 2001 to 2003, and with a focus on midstream master limited partnerships, or MLPs. Mr. Brauchle was a postgraduate technical assistant at the Financial Accounting Standards Board (FASB) from 1996 to 1997. Mr. Brauchle is a Certified Public Accountant and a graduate of Texas A&M University, where he received a Master of Science in Accounting in 1996 and a Bachelor of Business Administration in Accounting in 1995. George E. Rider has been Executive Vice President, General Counsel and Secretary of our general partner since February 2013 and has held the same positions for GP Holdings since February 2013 and for Tallgrass Development and its general partner since August 2012. From 2008 to August 2012, Mr. Rider was Vice President and General Counsel for Tallgrass Capital, LLC and its affiliate, Tallgrass MLP Fund I, L.P., a private MLP Investment Fund. From 1986 to 2008, Mr. Rider was an attorney with the law firm that is now known as Stinson Leonard Street LLP, becoming a partner in 1987. Mr. Rider holds an undergraduate degree from Phillips University and a Juris Doctorate in Law from the University of Kansas, where he was a member of Order of the Coif. Richard L. Bullock has been Vice President of Human Resources, Tax and Risk Management of our general partner since February 2013 and has held the same positions for GP Holdings since February 2013 and for Tallgrass Development and its general partner since November 2012. Previously, Mr. Bullock served as the Vice President, Chief Financial Officer and Treasurer of Tallgrass Development and its general partner. Mr. Bullock previously served as Vice President and Chief Financial Officer of Tallgrass MLP Fund I, L.P. from 2008 to 2011. Prior to Tallgrass, Mr. Bullock worked at Kinder Morgan Energy Partners, L.P. Mr. Bullock joined Kinder Morgan Energy Partners, L.P. in 1997 where he served as Vice President, Controller and Chief Accounting Officer through 2002 and, thereafter served as Vice President-Tax through October 2008. In those roles Mr. Bullock was principally responsible for all quarterly and annual SEC filings, integrating the accounting and financial reporting functions for acquisitions, tax compliance and tax planning for both Kinder Morgan Energy Partners, L.P. and Kinder Morgan, Inc. Mr. Bullock is a Certified Public Accountant. He received his undergraduate degree in Accounting from Missouri State University in Springfield, Missouri. Gary D. Watkins has been Vice President and Chief Accounting Officer and the principal accounting officer of the general partner since April 2014. Previously, Mr. Watkins served as Vice President, Controller and principal accounting officer of DCP Midstream Partners, LP and DCP Midstream, LLC from May 2011 until April 2014. Prior to that, Mr. Watkins had held the positions of Senior Director—Marketing Accounting and Director of Corporate Accounting with DCP Midstream, LLC. Prior to joining DCP Midstream, LLC in November 2004, Mr. Watkins held various positions of increasing responsibility at Advanced Energy Industries, Inc. Mr. Watkins also served in the Denver offices of Arthur Andersen LLP and KPMG LLP from 1996 through 2002. Frank J. Loverro has served as a director of our general partner since February 2013 and has held the same position for GP Holdings (and its predecessor) since August 2012. Mr. Loverro joined Kelso in 1993 and has been Managing Director since 2004 and became a Member of Kelso’s Management Committee in 2013. He spent the preceding three years in the private equity investment and high yield groups at The First Boston Corporation. Mr. Loverro is also a director of Delphin Shipping LLC, Hunt Marcellus, LLC, Poseidon Containers Holdings LLC and Helios (the new name of Progressive Medical and PMSI). Mr. Loverro was also a director of Buckeye GP LLC. Mr. Loverro received a B.A. in Economics with Distinction from the University of Virginia in 1991. Mr. Loverro has extensive experience in corporate financing and in evaluating the financial performance and operations of companies across a variety of business sectors, including the energy sector. We believe that this background, in addition to Mr. Loverro’s valuable experience serving on the boards of various public and private companies, provides an important source of insight and perspective to the board of directors of our general partner. 125 Stanley de J. Osborne has served as a director of our general partner since February 2013 and has held the same position for GP Holdings (and its predecessor) since August 2012. Mr. Osborne joined Kelso in 1998 and has been Managing Director since 2007. He spent the preceding two years as an Associate at Summit Partners. He spent the previous three years at J.P. Morgan & Co. as an Associate in the Private Equity Group and an Analyst in the Financial Institutions Group. Mr. Osborne is also a director of 4Refuel Canada LP, Hunt Marcellus, LLC, Logan’s Roadhouse, Inc., Traxys S.a.r.l and Power Team Services, LLC. Mr. Osborne was also previously a director of CVR Energy, Inc. and Global Geophysical Services, Inc. Mr. Osborne received a B.A. in Government from Dartmouth College in 1993. Mr. Osborne has extensive experience in corporate financing and in evaluating the financial performance and operations of companies across a variety of business sectors, including the energy sector. We believe that this background, in addition to Mr. Osborne’s valuable experience serving on the boards of various public and private companies, provides an important source of insight and perspective to the board of directors of our general partner. Jeffrey A. Ball has served as a director and Chairman of the Audit Committee of our general partner since February 2013 and as a director of the general partner of Tallgrass Development since August 2012. Mr. Ball is a Managing Director at EMG, a diversified natural resource private equity fund manager, and is responsible for transaction origination, structuring and execution, portfolio company management and investment realization. Prior to joining EMG in October 2007, Mr. Ball was a Director in the investment banking group at Credit Suisse Securities (USA), LLC, covering the energy industry with a particular focus on MLPs and the midstream sector. Mr. Ball has completed over $50 billion of mergers and acquisitions and capital markets financing transactions during his career in the energy and minerals sector. Mr. Ball currently serves on the Boards of Ferus Inc., Ferus GP LLC, Ferus Natural Gas Fuels Inc., Ferus Natural Gas Fuels GP, LLC, Ferus Natural Gas Fuels (CNG), LLC, American Energy Appalachia Holdings, LLC, American Energy Permian Basin Holdings, LLC and is a board observer of MarkWest Utica EMG, LLC. Mr. Ball received a B.S. in Economics with honors from the Wharton School at the University of Pennsylvania. We believe that Mr. Ball’s experience with mergers & acquisitions and financings of a variety of MLPs and other midstream assets provides a valuable resource to the board of directors of our general partner. John T. Raymond has served as a director of our general partner since February 2013 and has held the same position for the general partner of TD since August 2012. Mr. Raymond is an owner and founder of The Energy & Minerals Group. EMG is a diversified natural resource private equity fund manager with approximately $17.1 billion of regulatory assets under management (RAUM). EMG has allocated approximately $8.1 billion in commitments across the energy sector since inception. Mr. Raymond has been Managing Partner and CEO since EMG’s inception in 2006. Prior to that time, Mr. Raymond held leadership positions with various energy companies, including President and CEO of Plains Resources Inc., President and Chief Operating Officer of Plains Exploration and Production Company and Director of Development for Kinder Morgan, Inc. Mr. Raymond currently serves on numerous other boards, including the board of directors of each of NGL Energy Holdings, LLC, the general partner of NGL Energy Partners, LP, Plains All American GP LLC, the general partner of Plains All American Pipeline, LP, and PAA GP Holdings LLC, the general partner of Plains GP Holdings, LP. Mr. Raymond received a BSM degree from the A.B. Freeman School of Business at Tulane University with dual concentrations in finance and accounting. We believe that Mr. Raymond’s experience with investment in and management of a variety of upstream and midstream assets and operations provides a valuable resource to the board of directors of our general partner. Terrance D. Towner has served as a director of our general partner since August 2013 and has also served as a member of the audit committee of our general partner since August 2013. Mr. Towner currently provides advisory services to various private equity clients and private companies. Between 2000 and December 2014, Mr. Towner was employed by Watco Companies, a Kansas based transportation company, in various capacities, including Vice Chairman, President, COO and CFO. As President and COO, Mr. Towner was responsible for all operations, safety, quality, human resources, information services and the financial performance of Watco’s transportation, mechanical, and terminal and port divisions. Prior to joining Watco, Mr. Towner spent thirteen years in banking including three years as President and CEO of First State Bank & Trust Company of Pittsburg, Kansas. He also served for five years as President of Pitsco, a company that develops and markets computer based education products, and approximately two years as a financial and strategic consultant with Grant Thornton. Following his departure from Grant Thornton, Mr. Towner acquired Joplin.com, an internet service provider located in Joplin, Missouri and subsequently sold the company to Empire District Electric Company, a public utility. Mr. Towner earned his bachelor’s degree in Economics from Pittsburg State University in 1981 and his MBA from Pittsburg State University in 1993. Roy N. Cook has served as a director of our general partner since September 2013. From 2001 to 2013, Mr. Cook was employed by, and held a variety of roles within, the terminals division of Kinder Morgan, focusing on acquisitions, management, design and operations and specializing in the dry bulk side of the terminals business. Prior to 2001, Mr. Cook owned and managed several business in the service industry, including Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminals, Inc., each of which were sold to Kinder Morgan in 2001. Mr. Cook currently owns several small businesses across diverse industries, including a self-storage business, an electrical service company and a commercial real estate management and development company. He graduated from Kansas State University in 1979 with a B.S. degree in Agriculture Economics. 126 Jeffrey R. Armstrong has served as a director of our general partner since April 2014. He is also a member of the audit committee of our general partner. Mr. Armstrong also serves as a director and a member of the audit committee of the general partner of Arc Logistics Partners LP, a publicly traded limited partnership that is principally engaged in the terminalling, storage, throughput and transloading of crude oil and petroleum products. In August 2014, Mr. Armstrong became the Chief Executive Officer of Zenith Energy, LP, a privately held midstream energy company focused on international matters. In October 2014, Mr. Armstrong became the chairman of MID-SHIP Group, a privately held logistics and transportation company. From March 2001 until December 2013, Mr. Armstrong was employed by Kinder Morgan and held various positions within the company including Vice President of Corporate Strategy and President of the Terminals division. Prior to 2001, Mr. Armstrong was employed by GATX Corporation where he held various commercial and operational roles including General Manager of the company’s east coast operations. He received his bachelor’s degree from the U.S. Merchant Marine Academy and an MBA from the University of Notre Dame. Audit Committee The Board of Directors of our General Partner has a standing audit committee which is currently composed of three directors, Jeffrey A. Ball, Terrance D. Towner, and Jeffrey R. Armstrong. Each audit committee member has past experience in accounting or related financial management experience. The board has determined that all of our audit committee members are independent under Section 303A.02 of the NYSE listing standards and Rule 10A-3 of the Securities Exchange Act of 1934, as amended. In making the independence determination, the board considered the requirements of the NYSE, the SEC and our Code of Business Conduct and Ethics. Among other factors, the board considered current or previous employment with us, our auditors or their affiliates by the director or his immediate family members, ownership of our voting securities and other material relationships with us. The audit committee has adopted a charter, which has been ratified and approved by the board of directors. Jeffrey A. Ball has been designated by the board as the audit committee’s financial expert meeting the requirements promulgated by the SEC and set forth in Item 407(d) of Regulation S-K of the Securities Exchange Act of 1934, as amended, based upon his education and employment experience as more fully detailed in Mr. Ball’s biography set forth above. Mr. Ball also acts as the Chairman of our audit committee. Conflicts Committee The Board of Directors of our General Partner periodically establishes a conflicts committee comprised of independent directors to resolve potential conflicts of interest between our general partner and its affiliates, on one hand, and us and our unitholders, on the other. The conflicts committee currently consists of three independent directors, Roy Cook, Terry Towner and Jeff Armstrong, with Roy Cook currently acting as the chairman. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, to have been approved by all of our unitholders, and not to involve a breach of any duties that may be owed to our unitholders. The conflicts committee is currently evaluating our potential acquisition of an additional 33.3% interest in Pony Express from Tallgrass Development. Corporate Governance Guidelines and Code of Business Conduct and Ethics Our general partner has adopted Corporate Governance Guidelines and a Code of Business Conduct and Ethics applicable to all of our employees, officers and directors with regard to Partnership-related activities. The Corporate Governance Guidelines and the Code of Business Ethics incorporate guidelines designed to deter wrongdoing and to promote honest and ethical conduct and compliance with applicable laws and regulations. They also incorporate expectations of our employees that enable us to provide accurate and timely disclosure in our filings with the SEC and other public communications. A copy of the Corporate Governance Guidelines and the Code of Business Conduct and Ethics are available to any person, free of charge, at our website at www.tallgrassenergy.com. Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Exchange Act requires our general partner’s board of directors and executive officers, and persons who own more than 10% of a registered class of our equity securities, to file with the SEC, and any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes in ownership of our common units and other equity securities. Officers, directors and greater than 10% unitholders are required by the SEC’s regulations to furnish to us and any exchange or other system on which such securities are traded or quoted with copies of all Section 16(a) forms they file with the SEC. Based solely upon a review of Forms 3, 4 and 5, and amendments thereto, we know of no director, officer, or beneficial owner of more than 10% of any class of our equity securities registered pursuant to Section 12 of the Exchange Act that failed to file timely any reports required to be furnished during 2014 pursuant to Section 16(a) of the Exchange Act, except that on February 25, 2014, Gary J. Brauchle filed a Form 4 that was due on February 14, 2014 and on February 18, 2015 Richard L. Bullock filed a Form 5 that was due on February 17, 2015. 127 Item 11. Executive Compensation Executive Compensation We and our general partner were formed in Delaware in February 2013. We do not directly employ any of the persons responsible for managing our business. Our business is managed and operated by the directors and executive officers of our general partner. All employees, including the executive officers of our general partner, are employed by an affiliate of our general partner, Tallgrass Management, LLC. Compensation of our executive officers is set by Tallgrass GP Holdings, LLC. The Partnership reimburses TD for all salaries, related benefits and compensation expenses for the employees of Tallgrass Management, LLC who provide services to the Partnership pursuant to an allocation agreed upon between TD and the Partnership under the terms of the Omnibus Agreement. Other than the employment agreement with our chief executive officer, David G. Dehaemers, Jr., none of our executive officers have entered into any employment agreements with Tallgrass Management, LLC, our general partner or any other affiliate. Summary Compensation Table The following table reflects the total compensation of the principal executive officer and of the three other most highly compensated executive officers of our general partner for 2014 (the "named executive officers") for services rendered to all Tallgrass-related entities, including the Partnership, Tallgrass Management, LLC and TD for the fiscal year ending December 31, 2014. David G. Dehaemers, Jr. President, Chief Executive Officer and Director William R. Moler Executive Vice President, Chief Operating Officer and Director Gary J. Brauchle Executive Vice President and Chief Financial Officer George E. Rider Executive Vice President, General Counsel and Secretary Year 2014 2013 2014 2013 2014 2013 2014 2013 Salary Bonus (1) EPU Awards (2) All Other Compensation (3) Total $ 301,000 $ 250,000 $ $ 300,000 $ 100,000 $ — $ — $ 31,274 $ 582,274 33,186 $ 433,186 $ 301,000 $ 500,000 $ $ 275,000 $ 200,000 — $ $ $ 874,500 $ 276,000 $ 500,000 $ $ 250,000 $ 200,000 — $ $ $ 874,500 $ 276,000 $ 500,000 $ $ 250,000 $ 200,000 — $ $ $ 874,500 30,436 $ 30,578 831,436 $ 1,380,078 26,059 $ 26,432 802,059 $ 1,350,932 29,930 $ 27,893 805,930 $ 1,352,393 (1) Represents discretionary bonuses paid in 2015 and 2014 based on performance in 2014 and 2013, respectively. (2) The amounts in this column represent the aggregate grant date fair value determined in accordance with ASC Topic 718 for equity participation units, or EPUs, granted in June 2013 under the Tallgrass MLP GP, LLC Long-Term Incentive Plan. Pursuant to SEC rules, the amounts shown in the Summary Compensation Table for awards subject to performance conditions are based on the probable outcome as of the date of grant and exclude the impact of estimated forfeitures. The EPU grants are measured at their grant date fair value. The EPUs are non-participating, 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 (but non- participating) future dividends during the vesting period. For additional information, see Note 15 –Equity-Based Compensation to our Consolidated Financial Statements in Item 8.—Financial Statements and Supplementary Data in this Annual Report. These amounts do not correspond to the actual value that will be recognized by the executive. (3) The amounts in the column include the following: contributions under the 401(k) savings plan (includes $30,000 for Mr. Dehaemers, $29,615 for Mr. Moler, $25,519 for Mr. Brauchle and $26,366 for Mr. Rider for the year ended December 31, 2014 and $30,000 for Mr. Dehaemers, $27,500 for Mr. Moler, $23,460 for Mr. Brauchle and $24,923 for Mr. Rider for the year ended December 31, 2013) and the dollar value of premiums paid for group life, accidental death and dismemberment insurance. 128 Employment Agreement On May 17, 2013, Mr. Dehaemers entered into an amended and restated employment agreement with Tallgrass Management, LLC, Tallgrass Development GP, LLC, Tallgrass GP Holdings, LLC and our general partner pursuant to which he agreed to serve as their President and Chief Executive Officer. Under the terms of the employment agreement, Mr. Dehaemers is entitled to receive an annual salary of $300,000. In addition, Mr. Dehaemers is entitled to receive (i) benefits that are normally provided to senior executives of Tallgrass Management, LLC, (ii) reimbursement for all ordinary and necessary out- of-pocket expenses incurred by Mr. Dehaemers, and (iii) a policy of directors and officers liability insurance. Mr. Dehaemers’ employment is "at-will" and may be terminated at any time. For a discussion of certain payments that Mr. Dehaemers may be entitled to upon the termination of his employment, please read "—Potential Payments Upon Termination or a Change in Control." Outstanding Equity Awards at Fiscal Year-End The following table reflects all outstanding equity awards of our named executive officers as of December 31, 2014. Equity Participation Unit Awards (1) Number of EPU Awards That Have Not Vested(2) Market Value of EPU Awards That Have Not Vested(3) Number of Unearned EPUs That Have Not Vested Market or Payout Value of Unearned EPUs That Have Not Vested David G. Dehaemers, Jr............... William R. Moler......................... Gary J. Brauchle .......................... George Rider................................ — $ $ 50,000 50,000 50,000 $ $ — 2,235,000 2,235,000 2,235,000 — $ — $ — $ — $ — — — — (1) The plan administrator may make grants of equity participation units under the plan containing such terms as the plan administrator shall determine, including the period over which equity participation units granted will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial or other performance objectives. The award agreements pursuant to which the EPUs set forth above were granted to provide for the settlement of the EPUs in common units. (2) Vesting of the EPUs is contingent upon the Pony Express System being placed into commercial service and will occur in two parts, with one-third vesting on the later of the Pony Express System in-service date or May 13, 2015, and the remaining two-thirds vesting on the later of the Pony Express System in-service date or May 13, 2017. The Pony Express System was placed in service in October 2014. (3) Reflects the closing price of $44.70 per TEP common unit at December 31, 2014. Long-Term Incentive Plan Our general partner has adopted the Tallgrass MLP GP, LLC Long-Term Incentive Plan, or LTIP, for officers, directors, employees and consultants of our general partner and its affiliates. We may issue our executive officers long-term equity based awards under the plan, which awards are intended to compensate the officers based on the performance of our common units and their continued employment during the vesting period, as well as align their long-term interests with those of our unitholders. We are responsible for our allocable share of the cost of awards granted under the LTIP. For more information regarding the LTIP, see Note 15 –Equity-Based Compensation to our Consolidated Financial Statements in Item 8.—Financial Statements and Supplementary Data of this Annual Report. Potential Payments Upon Termination or Change of Control Dehaemers’ Employment Agreement The employment agreement for Mr. Dehaemers provides that he will receive a severance payment equal to $900,000, payable in a lump sum within 60 days after the termination of his employment, in the event his employment is terminated without "cause" or in the event he resigns for "good reason." Under Mr. Dehaemers’ employment agreement: • "Cause" means (i) his conviction of, or plea of nolo contendere to, any crime or offense constituting a felony under applicable law; (ii) his commission of fraud or embezzlement against Tallgrass Management, LLC or certain of its affiliates; (iii) gross neglect by Mr. Dehaemers of, or gross or willful misconduct of Mr. Dehaemers in connection with the performance of, his duties that is not cured within 30 days of receiving a written notice of such gross neglect or gross or willful misconduct; (iv) Mr. Dehaemers’ willful failure or refusal to carry out the reasonable and lawful 129 instructions of the board of managers of Tallgrass GP Holdings, LLC; (v) Mr. Dehaemers’ failure to perform the duties and responsibilities of his office as his primary business activity; (vi) a judicial determination that Mr. Dehaemers has breached his fiduciary duties with respect to Tallgrass Management, LLC or certain of its affiliates; or (vii) Mr. Dehaemers’ willful and material breach of his obligations under the operating agreements of Tallgrass GP Holdings, LLC, Tallgrass Development GP, LLC, Tallgrass Development or our general partner, in his capacity as an officer of such entities. • "Good reason" means (i) during the period prior to Tallgrass Management, LLC or certain of its affiliates accessing the public markets (through an initial public offering, merger or otherwise), Kelso and EMG and their respective affiliates cease to hold, in the aggregate, a majority of certain equity interests issued to them on or about the date of our initial public offering; (ii) a material diminution of Mr. Dehaemers’ duties and responsibilities to Tallgrass Management, LLC or certain of its affiliates to a level inconsistent with those of a chief executive officer; (iii) a material reduction in Mr. Dehaemers’ cash compensation or the aggregate welfare benefits provided to him (excluding any reduction that is not limited to him specifically); (iv) a willful or intentional breach of his employment agreement by Tallgrass Management, LLC; or (v) a willful or intentional breach by Tallgrass GP Holdings, LLC, Tallgrass Development GP, LLC, Tallgrass Development, our general partner or certain investors in Tallgrass GP Holdings, LLC of a material provision of the applicable operating agreements of such entities that has a material and adverse effect on Mr. Dehaemers. In addition, under the terms of his employment agreement, Mr. Dehaemers has agreed not to compete with Tallgrass Management, LLC or certain of its affiliates and not to solicit Tallgrass Management, LLC’s or any of its affiliates’ employees or interfere with certain business relationships during the term of his employment and for one year thereafter. LTIP Awards Awards under the LTIP may vest and/or become exercisable, as applicable, upon a "change in control" of us or our general partner, if so provided by the plan administrator at the time of the grant. The consequences of the termination of a grantee’s employment, consulting arrangement or membership on the board of directors will be determined by the plan administrator in the terms of the relevant award agreement Compensation of Directors Officers or employees of TD or its affiliates, including directors affiliated with EMG or Kelso, who also serve as directors of our general partner do not receive additional compensation for such service. Directors of our general partner who are not also officers or employees of TD or its affiliates or affiliated with EMG or Kelso receive cash compensation as follows: • Quarterly cash retainer payments of $10,000, resulting in an effective annual cash retainer of $40,000. • For serving as the audit committee chair or the conflicts committee chair, an annual committee chair retainer of $5,000. All directors are also reimbursed for out-of-pocket expenses in connection with their service as directors, including costs incurred to attend meetings. Each director is fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law pursuant to our partnership agreement. Directors of our general partner are also eligible to receive grants under the LTIP. In 2014, the board of directors of our general partner approved a grant of 3,000 EPUs to three of our independent directors: Terrance D. Towner, Roy N. Cook, and Jeffrey R. Armstrong. Vesting of the EPUs granted to our independent directors is contingent upon the Pony Express System being placed in service and will occur in three parts, with one-third vesting on the later of the Pony Express System in-service date or May 13, 2015, one-third vesting on the later of the Pony Express System in-service date or May 13, 2016 and the remaining one-third vesting on the later of the Pony Express System in-service date or May 13, 2017. The Pony Express System was placed in service in October 2014. The following table sets forth certain information with respect to our non-employee director compensation during the year ended December 31, 2014. Name and Principal Position Terrance D. Towner................................. $ Roy N. Cook ........................................... $ Jeffrey R. Armstrong............................... $ Fees Earned or Paid in Cash (1) EPU Awards (2) Non-Equity Incentive Plan Compensation All Other Compensation Total 45,000 $ 45,000 $ 85,737 $ 85,737 $ 40,000 $ 104,853 $ — $ — $ — $ 1,316 $ $ 2,809 132,053 133,546 4,202 $ 149,055 (1) Includes cash retainer, meeting fees and committee chair fees. 130 (2) The amounts in this column represent the aggregate grant date fair value determined in accordance with ASC Topic 718 for equity participation units, or EPUs, granted in 2014 under the Tallgrass MLP GP, LLC Long-Term Incentive Plan. The EPU grants are measured at their grant date fair value. The EPUs are non-participating, 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 (but non-participating) future dividends during the vesting period. For additional information, see Note 15 – Equity-Based Compensation to our Consolidated Financial Statements in Item 8.—Financial Statements and Supplementary Data in this Annual Report. These amounts do not correspond to the actual value that will be recognized by the executive. Compensation Committee Interlocks and Insider Participation The listing rules of the NYSE do not require us to maintain, and we do not maintain, a compensation committee. Mr. Dehaemers, as President and Chief Executive Officer, and Mr. Moler, as Executive Vice President and Chief Operating Officer, participate in their capacity as a director of our general partner in the deliberations of the Board concerning executive officer compensation. In addition, Mr. Dehaemers makes recommendations to the board of directors regarding named executive officer compensation, but Mr. Dehaemers abstains from, and is not present for, any decisions regarding his compensation. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters The following table sets forth the beneficial ownership of our units as of February 19, 2015 owned by: • • • • each person known by us to be a beneficial owner of more than 5% of the units; each of the directors of our general partner; each of the named executive officers of our general partner; and all directors and executive officers of our general partner as a group. The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a "beneficial owner" of a security if that person has or shares "voting power," which includes the power to vote or to direct the voting of such security, or "investment power," which includes the power to dispose of or to direct the disposition of such security. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable. Percentage of total units to be beneficially owned is based on 49,034,105 common units outstanding as of February 19, 2015. Name of Beneficial Owner (1) Tallgrass Operations, LLC (2)......................................................................... Kayne Anderson Capital Advisers, L.P.(3) ..................................................... David G. Dehaemers, Jr. ............................................................................... William R. Moler .......................................................................................... Gary J. Brauchle............................................................................................ George E. Rider............................................................................................. Richard L. Bullock ........................................................................................ Gary D. Watkins............................................................................................ Frank J. Loverro ............................................................................................ Stanley de J. Osborne.................................................................................... Jeffrey A. Ball ............................................................................................... John T. Raymond........................................................................................... Roy N. Cook ................................................................................................. Terrance D. Towner....................................................................................... Jeffrey R. Armstrong..................................................................................... All directors and executive officers as a group (thirteen persons)................ * Less than 1%. 131 Common Units Beneficially Owned Percentage of Common Units Beneficially Owned 26,355,480 2,461,082 201,520 — 9,113 2,500 4,672 1,000 — — 20,000 100,000 40,000 4,000 — 382,633 54% 5% — — — — * * * * * * * * * * (1) Unless otherwise indicated, the address for all beneficial owners in this table is c/o Tallgrass Energy Partners, LP, 4200 W. 115th Street, Suite 350, Leawood, Kansas 66211, Attn: General Counsel. (2) Tallgrass Development GP, LLC, as the general partner of Tallgrass Development, which is the sole owner of Tallgrass Operations, LLC, has the sole voting and dispositive power with respect to the common units owned by Tallgrass Operations, LLC. Tallgrass Development GP, LLC is controlled by its sole member, Tallgrass GP Holdings, LLC. Tallgrass GP Holdings, LLC is, in turn, controlled by its board of directors, which currently consists of the following: David G. Dehaemers, Jr., William R. Moler, Frank J. Loverro, Stanley de J. Osborne, Jeffrey A. Ball and John T. Raymond. Each of the members of the board of directors of Tallgrass GP Holdings, LLC may be deemed to beneficially own the common units owned by Tallgrass Operations, LLC; however, each disclaims beneficial ownership. (3) As reported on Schedule 13G filed with the SEC on January 13, 2015. The business address for Kayne Anderson Capital Advisors, L.P. is 1800 Avenue of the Stars, Third Floor, Los Angeles, California 90067. Securities Authorized for Issuance Under Equity Compensation Plans The following table provides information about TEP’s common units that may be issued under equity compensation plans as of December 31, 2014: Plan category Equity compensation plans approved by security holders (1) Equity compensation plans not approved by security holders (2) Total (a) Number of securities to be issued upon exercise of outstanding options, warrants and rights (b) Weighted average grant date fair value of outstanding options, warrants and rights (c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) 1,525,750 $ — $ 1,525,750 $ 18.75 — 18.75 8,474,250 — 8,474,250 (1) Amounts shown represent equity participation unit awards outstanding under the LTIP as of December 31, 2013. The outstanding awards will be settled in common units pursuant to the terms of the award agreements and are not subject to an exercise price. (2) There are no equity compensation plans in place except for the LTIP. For additional information regarding the LTIP, see Note 15 - Equity-Based Compensation to our Consolidated Financial Statements in Item 8.—Financial Statements and Supplementary Data of this Annual Report. Item 13. Certain Relationships and Related Transactions, and Director Independence As of February 19, 2015, TD owned 26,355,480 common units representing approximately 53.7% of our outstanding limited partner common units. In addition, our general partner owns 834,391 general partner units representing an approximate 1.7% general partner interest in us and all of the incentive distribution rights. Distributions and Payments to Our General Partner and Its Affiliates The following information summarizes the distributions and payments made or to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and any liquidation of us. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations. Distributions of available cash to our general partner and its affiliates. We will generally make distributions of available cash to common unitholders pro rata (including TD as the holder of an aggregate of 26,355,480 common units) and to our general partner as follows: (1) an approximate 1.7% with respect to its general partner units and (2) as distributions of available cash exceed the MQD and other higher target levels specified in our partnership agreement, increasing percentages of distributions with respect to its IDRs, up to 48% of the distributions above the highest target level. Assuming we have sufficient available cash to pay the full MQD on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $1.0 million on their general partner units and $56.4 million on their common units. 132 Payments to our general partner and its affiliates. Neither our general partner nor TD’s general partner and its affiliates receive a management fee or other compensation for managing us. Our general partner and TD’s general partner and its affiliates are reimbursed, however, for all direct and indirect expenses incurred on our behalf pursuant to our partnership agreement and the Omnibus Agreement. Neither our partnership agreement nor the Omnibus Agreement limit the amount of expenses for which our general partner or TD’s general partner and its affiliates may be reimbursed. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. Withdrawal or removal of our general partner. If our general partner withdraws or is removed, its general partner interest and its IDRs will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Liquidation Stage. Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances, as further detailed in our limited partnership agreement. Agreements with Affiliates in Connection with the IPO We entered into various documents and agreements with TD and its other affiliates in connection with the IPO. These are primarily related to our formation, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds of the IPO. These agreements were not the result of arm’s length negotiations. Omnibus Agreement Upon the closing of the IPO, we entered into an Omnibus Agreement with TD, its general partner and our general partner that governs our relationship with them regarding the following matters: • • • • • the provision by TD’s general partner to us of certain administrative services and our agreement to reimburse it for such services; the provision by TD’s general partner of such employees as may be necessary to operate and manage our business, and our agreement to reimburse it for the expenses associated with such employees; certain indemnification obligations; our use of the name "Tallgrass" and related marks; and our right of first offer to acquire certain assets, including each of the Retained Assets from TD, if Tallgrass Development decides to sell such assets. Reimbursement of General and Administrative Expenses Pursuant to the Omnibus Agreement, the general partner of TD performs, or causes its affiliates to perform, centralized corporate, general and administrative services for us, such as legal, corporate record keeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. In exchange, we reimburse it for expenses incurred in providing these services. The reimbursements to our general partner and TD’s general partner and its affiliates are made prior to cash distributions to our common unitholders. The Omnibus Agreement further provides that we will reimburse the general partner of TD and its affiliates for our allocable portion of the premiums on any insurance policies covering our assets. We anticipate reimbursement to TD’s general partner and its affiliates will vary with the size and scale of our operations, among other factors. Indemnification Under the terms of the Omnibus Agreement, TD is required to indemnify us from liabilities arising out of any federal, state and local income tax liabilities attributable to the ownership and operation of the assets contributed to us in connection with the IPO until 60 days after the applicable statute of limitations. TD also agreed to use commercially reasonable efforts to obtain indemnification from Kinder Morgan for losses suffered or incurred by us with respect to the assets contributed to us as part of the IPO, to the extent that Kinder Morgan is obligated to indemnify TD under the purchase and sale agreement pursuant to which TD acquired the contributed assets and remit any proceeds received from Kinder Morgan pursuant to such indemnification obligations to us. Kinder Morgan’s indemnity obligations under the Kinder Morgan purchase agreement generally survived through February 13, 2014, although certain specified indemnities last for longer periods of time. Under the Omnibus Agreement, we have agreed to indemnify TD for events and conditions associated with the operation of the contributed assets that occur on or after the closing of the IPO. 133 Right of First Offer Under the terms of the Omnibus Agreement, TD has granted us a right of first offer, for so long as TD or its affiliates, individually or as part of a group, control our general partner, on (i) the Retained Assets and (ii) any assets that are hereafter developed, constructed or acquired by TD or its subsidiaries (excluding the Partnership and its subsidiaries) for the purpose of processing natural gas in Natrona, Converse or Campbell counties in Wyoming, which we refer to collectively as the ROFO Assets. If TD or any of its affiliates decide to attempt to sell (other than to an affiliate of TD, excluding TEP and its subsidiaries) a ROFO Asset, TD or its affiliate will notify us in advance and, prior to selling such ROFO Asset to a third party, will negotiate with us exclusively and in good faith for a period of 45 days in order to give us an opportunity to enter into definitive documentation for the purchase and sale of such ROFO Asset on terms that are mutually acceptable to TD or its affiliate and us. If we and TD or its affiliate have not entered into a letter of intent or a definitive purchase and sale agreement with respect to such ROFO Asset within such 45-day period, TD or its affiliate will have the right to sell such ROFO Asset to a third party following the expiration of such 45-day period on any terms that are acceptable to TD or its affiliate and such third party. Our decision to acquire or not to acquire a ROFO Asset pursuant to this right will require the approval of the conflicts committee of the board of directors of our general partner. Amendment and Termination The Omnibus Agreement can be amended by written agreement of all parties to the agreement. However, we may not agree to any amendment or modification that would, in the determination of our general partner, be adverse in any material respect to the holders of our common units without the prior approval of the conflicts committee. In the event of (i) a "change in control" (as defined in the Omnibus Agreement) of the partnership or (ii) the removal of Tallgrass MLP GP, LLC as our general partner in circumstances where "cause" (as defined in our partnership agreement) does not exist and the common units held by our general partner and its affiliates were not voted in favor of such removal, the Omnibus Agreement (other than the indemnification and reimbursement provisions therein) will be terminable by TD, and we will have a 90-day transition period to cease our use of the name "Tallgrass" and related marks. Acquisition of Pony Express and Trailblazer from Tallgrass Development On April 1, 2014, Tallgrass MLP Operations, LLC, a Delaware limited liability company and our wholly-owned subsidiary acquired 100% of the issued and outstanding membership interests in Trailblazer from Tallgrass Operations, LLC, a Delaware limited liability company and wholly-owned direct subsidiary of Tallgrass Development ("Tallgrass Operations"), for total consideration valued at approximately $164 million, pursuant to that certain Contribution and Sale Agreement by and between Tallgrass Development, Tallgrass Operations, and us. Effective September 1, 2014, Tallgrass PXP Holdings, LLC, a Delaware limited liability company and our wholly-owned subsidiary ("PXP Holdings") acquired a 33.3% membership interest in Tallgrass Pony Express Pipeline, LLC, a Delaware limited liability company ("Pony Express"), from Tallgrass Development for total consideration of approximately $600 million pursuant to that certain Contribution and Transfer Agreement by and between Tallgrass Development, Pony Express, Tallgrass Operations, and us. At closing, we entered into a Second Amended and Restated Limited Liability Company Agreement of Pony Express effective September 1, 2014 with TD and Pony Express, which provides us a minimum quarterly preference payment of $16.65 million through the quarter ending September 30, 2015 with distributions thereafter shared in accordance with the terms of the Second Amended and Restated Limited Liability Company Agreement. In connection with the transaction, Pony Express entered into a Cash Management Agreement effective August 27, 2014 with Tallgrass Operations, under which cash balances are swept daily and recorded as loans from Pony Express to TD. $270 million of the total consideration was subsequently swept to TD and was recorded as a related party loan which bears interest at TD's incremental borrowing rate. As of September 1, 2014, balances lent to TD under the cash management agreement are classified as related party receivables on our consolidated balance sheet and will be cash settled. Competition Under our partnership agreement, TD and its affiliates are expressly permitted to compete with us. TD and any of its affiliates, including EMG and Kelso may acquire, construct or dispose of additional transportation, storage and processing or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets. 134 Contracts with Affiliates None. Other Transactions Tallgrass Management, LLC, an affiliate of our general partner, has two employees who are immediate family members of executive officers of our general partner. Jason Dehaemers, a director of corporate development, is the son of David Dehaemers, Jr., the President and Chief Executive Officer of our general partner and a member of our general partner’s board of directors. For 2014, he received cash compensation of $349,800 and standard employee benefits of approximately $17,424. Zach Rider, a manager of corporate development, is the son of George Rider, the Executive Vice President, General Counsel and Secretary of our general partner. For 2014, he received cash compensation of $161,680 and standard employee benefits of approximately $13,747. Procedures for Review, Approval or Ratification of Transactions with Related Persons The board of directors of our general partner has adopted a code of business conduct and ethics. Among other things, it provides that the board of directors of our general partner or its authorized committee will periodically review all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the code of business conduct and ethics provides that our management will make all reasonable efforts to cancel or annul the transaction. The code of business conduct and ethics also provides that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director’s independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediate family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics. Director Independence The information required by Item 407(a) or Regulation S-K is included in Item 10. Directors, Executive Officers and Corporate Governance. Item 14. Principal Accounting Fees and Services We have engaged PricewaterhouseCoopers LLP as our independent registered public accounting firm. The following table summarizes fees we were billed by PricewaterhouseCoopers LLP (or included in TD’s general and administrative expense allocation to us) for independent auditing, tax and related services for each of the last two fiscal years: Year Ended December 31, 2014 Year Ended December 31, 2013 Audit fees (1).......................................................... Audit related fees (2).............................................. Tax fees (3)............................................................. Total...................................................................... $ $ (in thousands) 1,137 $ — 346 1,483 $ 1,516 — 210 1,726 (1) Audit fees represent amounts billed for each of the years presented for professional services rendered in connection with (i) the integrated audit of our annual financial statements and internal control over financial reporting, (ii) the review of our quarterly financial statements or (iii) those services normally provided in connection with statutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters. This information is presented as of the latest practicable date for this Annual Report. (2) Audit-related fees represent amounts we were billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterly reviews of our financial statements and are not reported under audit fees. 135 (3) Tax fees represent amounts we were billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice and tax planning. All services provided by our independent registered public accountant are subject to pre-approval by the audit committee of our general partner. The audit committee of our general partner is informed of each engagement of the independent registered public accountant to provide services under the policy. The audit committee of our general partner has approved the use of PricewaterhouseCoopers LLP as our independent registered public accounting firm. 136 Item 15. Exhibits, Financial Statement Schedules (1) Financial Statements PART IV (a) (b) (c) (d) (e) (f) Reports of Independent Registered Public Accounting Firm Consolidated Balance Sheets as of December 31, 2014 and 2013 Consolidated Statements of Income (Loss) for the years ended December 31, 2014 and 2013, the period from November 13, 2012 to December 31, 2012, and the period from January 1, 2012 to November 12, 2012 Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2014 and 2013, the period from November 13, 2012 to December 31, 2012 and the period from January 1, 2012 to November 12, 2012 Consolidated Statements of Partners' Capital for the years ended December 31, 2014 and 2013, the period from November 13, 2012 to December 31, 2012, and the period from January 1, 2012 to November 12, 2012 Consolidated Statements of Cash Flows for the years ended December 31, 2014 and 2013, the period from November 13, 2012 to December 31, 2012, and the period from January 1, 2012 to November 12, 2012 (g) Notes to Consolidated Financial Statements (2) Financial Statement Schedules Page No. 78-79 80 81 82 83 84 85 All schedules are omitted because the required information is either not present, not present in material amounts or included within the Consolidated Financial Statements. (3) Exhibits Exhibit No. 3.1 3.2 3.3 3.4 3.5 3.6 3.7 Description Certificate of Limited Partnership of Tallgrass Energy Partners, LP (incorporated by reference to Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 (File No. 333-187595) filed on March 28, 2013). Certificate of Amendment to Certificate of Limited Partnership of Tallgrass Energy Partners, LP (incorporated by reference to Exhibit 3.2 to the Partnership’s Registration Statement on Form S-1 (File No. 333-187595) filed on March 28, 2013). Amended and Restated Agreement of Limited Partnership of Tallgrass Energy Partners, LP, dated May 17, 2013 (incorporated by reference to Exhibit 3.2 to the Partnership’s Current Report on Form 8-K filed on May 17, 2013). Certificate of Formation of Tallgrass MLP GP, LLC (incorporated by reference to Exhibit 3.4 to the Partnership’s Registration Statement on Form S-1 (File No. 333-187595) filed on March 28, 2013). Second Amended and Restated Limited Liability Company Agreement of Tallgrass MLP GP, LLC, dated May 17, 2013 (incorporated by reference to Exhibit 3.4 to the Partnership’s Current Report on Form 8-K filed on May 17, 2013). Second Amended and Restated Limited Liability Company Agreement of Tallgrass Pony Express Pipeline, LLC, dated September 1, 2014 (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K filed on September 8, 2014). Amendment No. 1, dated September 29, 2014, to Second Amended and Restated Limited Liability Company Agreement of Tallgrass Pony Express Pipeline, LLC, dated September 1, 2014 (incorporated by reference to Exhibit 10.3 to the Partnership’s Quarterly Report on Form 10-Q filed on October 30, 2014). 3.8* Amendment No. 1, dated February 19, 2015, to Second Amended and Restated Limited Liability Company Agreement of Tallgrass MLP GP, LLC, dated May 17, 2013. 137 10.1 10.2 10.3 10.4 10.5 † 10.6 † 10.7 † 10.8 10.9 10.10 21.1* 23.1* 31.1* 31.2* 32.1* 32.2* 101.INS* 101.SCH* 101.CAL* 101.DEF* 101.LAB* 101.PRE* * - filed herewith Contribution, Conveyance and Assumption Agreement, dated May 17, 2013, by and among Tallgrass Energy Partners, LP, Tallgrass MLP GP, LLC, Tallgrass Development, LP, Tallgrass Development GP, LLC, Tallgrass GP Holdings, LLC, Tallgrass Operations, LLC, Tallgrass Interstate Gas Transmission, LLC, Tallgrass Midstream, LLC and Tallgrass MLP Operations, LLC (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on May 17, 2013). Omnibus Agreement, dated May 17, 2013, by and among Tallgrass Development, LP, Tallgrass Energy Partners, LP, Tallgrass MLP GP, LLC and Tallgrass Development GP, LLC (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8- K filed on May 17, 2013). Revolving Credit Agreement, dated May 17, 2013, 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 10.3 to the Partnership’s Current Report on Form 8- K filed on May 17, 2013). Amendment No. 1, dated June 25, 2014, to the Revolving Credit Agreement, dated May 17, 2013, 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). Tallgrass MLP GP, LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to the Partnership’s Current Report on Form 8-K filed on May 17, 2013). Form of Employee Equity Participation Unit Agreement (incorporated by reference to Exhibit 4.5 to the Partnership’s Registration Statement on Form S-8 filed on June 18, 2013). Amended and Restated Employment Agreement, dated May 17, 2013, by and among Tallgrass Management, LLC, Tallgrass Development GP, LLC, Tallgrass GP Holdings, LLC, Tallgrass MLP GP, LLC and David G. Dehaemers, Jr. (incorporated by reference to Exhibit 10.5 to the Partnership’s Registration Statement on Form S-1/A (File No. 333-187595) filed on April 18, 2013). Purchase and Sale Agreement, dated August 1, 2012, between Kinder Morgan Interstate Gas Transmission LLC and Kinder Morgan Pony Express Pipeline LLC (incorporated by reference to Exhibit 10.7 to the Partnership’s Registration Statement on Form S-1/A (File No. 333-187595) filed on April 8, 2013). Contribution and Sale Agreement, dated April 1, 2014, by and between Tallgrass Energy Partners, LP and Tallgrass Operations, LLC, and for certain limited purposes, Tallgrass Development, LP (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on April 2, 2014). Contribution and Transfer Agreement, dated September 1, 2014, by and among Tallgrass Energy Partners, LP, Tallgrass Operations, LLC and Tallgrass Pony Express Pipeline, LLC, and for certain limited purposes, Tallgrass Development, LP (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on September 8, 2014). List of Subsidiaries of Tallgrass Energy Partners, LP. Consent of PricewaterhouseCoopers LLP. Rule 13a-14(a)/15d-14(a) Certification of David G. Dehaemers, Jr. Rule 13a-14(a)/15d-14(a) Certification of Gary J. Brauchle. Section 1350 Certification of David G. Dehaemers, Jr. Section 1350 Certification of Gary J. Brauchle. XBRL Instance Document. XBRL Taxonomy Extension Schema Document. XBRL Taxonomy Extension Calculation Linkbase Document. XBRL Taxonomy Extension Definition Linkbase Document. XBRL Taxonomy Extension Label Linkbase Document. XBRL Taxonomy Extension Presentation Linkbase Document. † - Management contract of compensatory plan or arrangement required to be filed as an exhibit to this Form 10-K pursuant to Item 15(b). 138 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Name Title Date /s/ David G. Dehaemers, Jr. David G. Dehaemers, Jr. Director, President and Chief Executive Officer February 19, 2015 (Principal Executive Officer) /s/ Gary J. Brauchle Gary J. Brauchle /s/ Gary D. Watkins Gary D. Watkins /s/ Frank J. Loverro Frank J. Loverro /s/ Stanley de J. Osborne Stanley de J. Osborne /s/ Jeffrey A. Ball Jeffrey A. Ball /s/ John T. Raymond John T. Raymond /s/ William R. Moler William R. Moler /s/ Terrance D. Towner Terrance D. Towner /s/ Roy N. Cook Roy N. Cook /s/ Jeffrey R. Armstrong Jeffrey R. Armstrong Executive Vice President and Chief Financial Officer February 19, 2015 (Principal Financial Officer) Vice President and Chief Accounting Officer February 19, 2015 (Principal Accounting Officer) February 19, 2015 February 19, 2015 February 19, 2015 February 19, 2015 February 19, 2015 February 19, 2015 February 19, 2015 February 19, 2015 Director Director Director Director Director Director Director Director 139 Exhibit 3.8 AMENDMENT NUMBER ONE TO SECOND AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT OF TALLGRASS MLP GP, LLC This Amendment Number One (“Amendment”) to the Second Amended and Restated Limited Liability Company Agreement of Tallgrass MLP GP, LLC, a Delaware limited liability company (the “Company”), dated as of May 17, 2013 (the “Agreement”), is hereby made and entered into as of February 19, 2015 (the “Effective Date”). Capitalized terms used but not defined herein are used as defined in the Agreement. RECITALS WHEREAS, the sole member of the Company has determined that it is in the best interest of the Company to modify the Agreement as stated below, and has approved the Amendment in accordance with the terms set forth below. NOW, THEREFORE, the Agreement is hereby amended as follows: Section 1. Amendment. Section 5.3 and Section 5.4 of the Agreement are each hereby amended to read in their entirety as follows: Section 5.3 Regular Meetings. Regular meetings of the Board shall be held at such time and place as shall be designated from time to time by the Chairman of the Board, the President, any Vice President, the Secretary, or by resolution of the Board. Section 5.4 Special Meetings. A special meeting of the Board may be called at any time at the request of the Chairman of the Board, the President, any Vice President, the Secretary, or a majority of the Directors then in office. Section 2. Ratification of Agreement. Except as expressly modified and amended herein, all of the terms and conditions of the Agreement shall remain in full force and effect. Section 3. Governing Law. This Amendment shall be construed in accordance with and governed by the laws of the State of Delaware without regard to principles of conflicts of laws. In witness whereof, the sole member has executed this Amendment as of the Effective Date. SOLE MEMBER: TALLGRASS GP HOLDINGS, LLC By: /s/ David G. Dehaemers, Jr. David G. Dehaemers, Jr. President and Chief Executive Officer Tallgrass Energy Partners, LP Subsidiaries Exhibit 21.1 Jurisdiction of Organization Company Tallgrass MLP Operations, LLC.............................................. Delaware Tallgrass Interstate Gas Transmission, LLC............................ Colorado Tallgrass Midstream, LLC....................................................... Delaware Tallgrass Energy Investments, LLC ........................................ Delaware Trailblazer Pipeline Company LLC ........................................ Delaware Tallgrass PXP Holdings, LLC................................................. Delaware Tallgrass Pony Express Pipeline, LLC.................................... Delaware Tallgrass Pony Express Pipeline (Colorado), Inc.................... Colorado NECL Realty Holdings, LLC .................................................. Delaware BNN Water Solutions, LLC..................................................... Delaware BNN Redtail, LLC................................................................... Delaware Alpha Reclaim Technology, LLC............................................ Texas BNN West Texas, LLC............................................................ Delaware BNN Recycle, LLC ................................................................. Delaware CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We hereby consent to the incorporation by reference in the Registration Statement on Form (No. 333-189417) of Tallgrass Energy Partners, LP of our reports dated February 19, 2015 relating to the financial statements of Tallgrass Energy Partners, LP and March 18, 2013 relating to the financial statements of TEP Pre-Predecessor which appear in this Form (No. 333-196454) and Exhibit 23.1 /s/ PricewaterhouseCoopers LLP Denver, Colorado February 19, 2015 Certification by Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 I, David G. Dehaemers, Jr., certify that: Exhibit 31.1 1. 2. 3. 4 I have reviewed this Quarterly Report on Form 10-Q of Tallgrass Energy Partners, LP; Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: a) b) c) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting. 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): a) b) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. By: /s/ David G. Dehaemers, Jr. David G. Dehaemers, Jr. President and Chief Executive Officer of Tallgrass MLP GP, LLC (the general partner of Tallgrass Energy Partners, LP) Date: February 19, 2015 Certification by Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 I, Gary J. Brauchle, certify that: Exhibit 31.2 1. 2. 3. 4 I have reviewed this Quarterly Report on Form 10-Q of Tallgrass Energy Partners, LP; Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: a) b) c) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting. 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): a) b) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. By: /s/ Gary J. Brauchle Gary J. Brauchle Executive Vice President, Chief Financial Officer and Treasurer of Tallgrass MLP GP, LLC (the general partner of Tallgrass Energy Partners, LP) Date: February 19, 2015 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 Exhibit 32.1 In connection with the quarterly report of Tallgrass Energy Partners, LP (the “Partnership”) on Form 10-Q for the quarter ended December 31, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David G. Dehaemers, Jr., President and Chief Executive Officer of Tallgrass MLP GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“Section 906”), that, to my knowledge: 1. 2. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership. By: /s/ David G. Dehaemers, Jr. David G. Dehaemers, Jr. President and Chief Executive Officer of Tallgrass MLP GP, LLC (the general partner of Tallgrass Energy Partners, LP) Date: February 19, 2015 A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained and furnished to the Securities and Exchange Commission or its staff upon request. Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 Exhibit 32.2 In connection with the quarterly report of Tallgrass Energy Partners, LP (the “Partnership”) on Form 10-Q for the quarter ended December 31, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David G. Dehaemers, Jr., President and Chief Executive Officer of Tallgrass MLP GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“Section 906”), that, to my knowledge: 1. 2. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership. By: /s/Gary J. Brauchle Gary J. Brauchle Executive Vice President, Chief Financial Officer and Treasurer of Tallgrass MLP GP, LLC (the general partner of Tallgrass Energy Partners, LP) Date: February 19, 2015 A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained and furnished to the Securities and Exchange Commission or its staff upon request. TALLGRASS ENERGY PARTNERS, LP • 2014 ANNUAL REPORT CORPORATE INFORMATION BOARD OF DIRECTORS David G. Dehaemers, Jr. William R. Moler Jeffrey R. Armstrong Jeffrey A. Ball Roy N. Cook Frank J. Loverro Stanley de J. Osborne John T. Raymond Terrance D. Towner EXECUTIVE MANAGEMENT David G. Dehaemers, Jr. President and Chief Executive Officer W. R. (Bill) Moler Executive Vice President & Chief Operating Officer Gary J. Brauchle Executive Vice President & Chief Financial Officer George E. Rider Executive Vice President, General Counsel & Secretary PUBLIC HEADQUARTERS 4200 W. 115th Street Suite 350 Leawood, KS 66211 (913) 928-6012 TALLGRASS ENERGY 4200 W. 115th Street Suite 350 Leawood, KS 66211 (913) 928-6012 370 Van Gordon Street Lakewood, CO 80228 (303) 763-2950 INVESTOR RELATIONS (913) 928-6012 investor.relations@tallgrassenergylp.com MEDIA RELATIONS (913) 928-6014 media.relations@tallgrassenergylp.com TRANSFER AGENT American Stock Transfer and Trust TICKER SYMBOL NYSE:TEP m o c . y g r e n e s s a r g l l a t . w w w • 2 1 0 6 - 8 2 9 ) 3 1 9 ( • 1 1 2 6 6 S K , d o o w a e L , 0 5 3 e t i u S , t e e r t S h t 5 1 1 . W 0 0 2 4 

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