10-K 1 ngls-10k_20161231.htm NGLS-10K-20161231 ngls-10k_20161231.htm

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2016

OR

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

For the transition period from            to           

Commission File Number: 001-33303

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)

 

Delaware

 

65-1295427

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer Identification No.)

 

 

 

1000 Louisiana St, Suite 4300, Houston, Texas

 

77002

(Address of principal executive offices)

 

(Zip Code)

 

(713) 584-1000

(Registrant’s telephone number, including area code)

 

Securities registered pursuant to section 12(b) of the Act:

 

Title of each class

 

Name of each exchange on which registered

9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

 

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

 

 

 

 

 

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 .

As of February 10, 2017, there were 5,000,000 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

 

None

 

 

 

 

 

 


TABLE OF CONTENTS

 

PART I

 

 

 

Item 1. Business.

 

4

 

 

 

Item 1A. Risk Factors

 

30

 

 

 

Item 1B. Unresolved Staff Comments.

 

49

 

 

 

Item 2. Properties.

 

49

 

 

 

Item 3. Legal Proceedings.

 

49

 

 

 

Item 4. Mine Safety Disclosures.

 

50

 

 

 

PART II

 

 

 

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

 

51

 

 

 

Item 6. Selected Financial Data.

 

53

 

 

 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

54

 

 

 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

 

80

 

 

 

Item 8. Financial Statements and Supplementary Data.

 

85

 

 

 

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.

 

85

 

 

 

Item 9A. Controls and Procedures.

 

85

 

 

 

Item 9B. Other Information.

 

85

 

 

 

PART III

 

 

 

Item 10. Directors, Executive Officers and Corporate Governance.

 

86

 

 

 

Item 11. Executive Compensation.

 

91

 

 

 

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

 

119

 

 

 

Item 13. Certain Relationships and Related Transactions, and Director Independence.

 

121

 

 

 

Item 14. Principal Accounting Fees and Services.

 

125

 

 

 

PART IV

 

 

 

Item 15. Exhibits, Financial Statement Schedules

 

125

 

Item 16. Form 10-K Summary

 

133

 

SIGNATURES

 

 

 

Signatures

 

134

 

 


 

1


CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

 

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

 

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

 

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the following risks and uncertainties:

 

 

the timing and extent of changes in natural gas, natural gas liquids (“NGL”), crude oil and other commodity prices, interest rates and demand for our services;

 

 

the level and success of crude oil and natural gas drilling around our assets, our success in connecting natural gas supplies to our gathering and processing systems, oil supplies to our gathering systems and NGL supplies to our logistics and marketing facilities and our success in connecting our facilities to transportation services and markets;

 

 

our ability to access the capital markets, which will depend on general market conditions and the credit ratings for our debt obligations;

 

 

the amount of collateral required to be posted from time to time in our transactions;

 

 

our success in risk management activities, including the use of derivative instruments to hedge commodity price risks;

 

 

the level of creditworthiness of counterparties to various transactions with us;

 

 

changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment;

 

 

weather and other natural phenomena;

 

 

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

 

 

our ability to obtain necessary licenses, permits and other approvals;

 

 

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

 

 

general economic, market and business conditions; and

 

 

the risks described elsewhere in “Item 1A. Risk Factors.” in this Annual Report and our reports and registration statements filed from time to time with the United States Securities and Exchange Commission (“SEC”).

 

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

 

 

 

 

 

2


 

 

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

 

Bbl

Barrels (equal to 42 U.S. gallons)

BBtu

Billion British thermal units

Bcf

Billion cubic feet

Btu

British thermal units, a measure of heating value

/d

Per day

GAAP

Accounting principles generally accepted in the United States of America

gal

U.S. gallons

GPM

Liquid volume equivalent expressed as gallons per 1000 cu. ft. of natural gas

LIBOR

London Interbank Offered Rate

LPG

Liquefied petroleum gas

MBbl

Thousand barrels

MMBbl

Million barrels

MMBtu

Million British thermal units

MMcf

Million cubic feet

MMgal

Million U.S. gallons

NGL(s)

Natural gas liquid(s)

NYMEX

New York Mercantile Exchange

NYSE

New York Stock Exchange

 

 

 

 

Price Index Definitions

 

C2-OPIS-MB

Ethane, Oil Price Information Service, Mont Belvieu, Texas

C3-OPIS-MB

Propane, Oil Price Information Service, Mont Belvieu, Texas

C5-OPIS-MB

Natural Gasoline, Oil Price Information Service, Mont Belvieu, Texas

EP-PERMIAN

Inside FERC Gas Market Report, El Paso (Permian Basin)

IC4-OPIS-MB

Iso-Butane, Oil Price Information Service, Mont Belvieu, Texas

IF-PB

Inside FERC Gas Market Report, Permian Basin

IF-PEPL

Inside FERC Gas Market Report, Oklahoma Panhandle, Texas-Oklahoma Midpoint

IF-WAHA

Inside FERC Gas Market Report, West Texas WAHA

NC4-OPIS-MB

Normal Butane, Oil Price Information Service, Mont Belvieu, Texas

NG-NYMEX

NYMEX, Natural Gas

WTI-NYMEX

NYMEX, West Texas Intermediate Crude Oil

 

 


3


PART I

Overview

 

Item 1. Business.

 

Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by our parent, Targa Resources Corp. (“Targa” or “TRC” or the “Company” or “Parent”), to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. TRP is a leading provider of midstream natural gas and NGL services in the United States, with a growing presence in crude oil gathering and petroleum terminaling.

 

On February 17, 2016, TRC completed the previously announced transactions contemplated by the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement”, “Buy-in Transaction”), by and among us, Targa Resources GP LLC (our “general partner”), TRC and Spartan Merger Sub LLC, a subsidiary of TRC (“Merger Sub”) pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the Merger Agreement, Merger Sub merged with and into TRP (the “TRC/TRP Merger”), with TRP continuing as the surviving entity and as a subsidiary of TRC. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units.

 

At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of common stock of TRC, par value $0.001 per share (“TRC shares”). No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares.

 

Pursuant to the TRC/TRP Merger Agreement, TRC has agreed to cause our common units to be delisted from the New York Stock Exchange (“NYSE”) and deregistered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). As a result of the completion of the TRC/TRP Merger, our common units are no longer publicly traded. Our 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) that were issued in October 2015 remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.”

 

References to "units" refers to our units representing limited partner interests in the Partnership and not to the Preferred Units (as defined herein), and "unitholders" refers to the holders of units. As used herein, unless the context requires otherwise, the term "limited partner interests" refers to the units, the Preferred Units and the Incentive Distribution Rights (“IDRs”), collectively, and “limited partners” refers to the holders of limited partner interests.

Our Operations

We are engaged in the business of:

 

gathering, compressing, treating, processing and selling natural gas;

 

storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters;

 

gathering, storing and terminaling crude oil; and

 

storing, terminaling and selling refined petroleum products.

To provide these services, we operate in two primary segments (previously referred to as divisions): (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business).

Concurrent with the TRC/TRP Merger, management reevaluated our reportable segments and determined that our previously disclosed divisions are the appropriate level of disclosure. The Gathering and Processing division was previously disaggregated into two reportable segments—(a) Field Gathering and Processing and (b) Coastal Gathering and Processing. The Logistics and Marketing division was previously disaggregated into two reportable segments—(a) Logistics Assets and (b) Marketing and Distribution. Management determined that the increase in activity within Field Gathering and Processing due to the acquisition by Targa of Atlas Energy LP (“ATLS”) and our acquisition of Atlas Pipeline Partners, L.P. (“APL”) (collectively, the “Atlas mergers”) coupled with the decline in activity in our Gulf Coast region makes the disaggregation of Field Gathering and Processing and Coastal Gathering and Processing no longer warranted. Management also determined that further disaggregation of our Logistics and Marketing segment is no longer appropriate due to the integrated nature of the operations within our Downstream Business and its leadership by a consolidated executive management team.

4


Our Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma and South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and Marketing segment includes all the activities necessary to convert mixed NGLs into NGL products and provides certain value added services such as storing, fractionating, terminaling, transporting and marketing of NGLs and NGL products, including services to LPG exporters; storing and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Marketing operations are generally connected to and supplied in part by our Gathering and Processing operations and are predominantly located in Mont Belvieu and Galena Park, Texas, Lake Charles, Louisiana and Tacoma, Washington.

 

Our midstream natural gas and NGL services footprint was initially established through several acquisitions from Targa, totaling $3.1 billion, that occurred from 2007 through 2010. Since the completion of the final acquisitions from Targa in 2010, we have grown substantially. The expansion of our business has been fueled by a combination of major organic growth investments in our businesses and third-party acquisitions. Third-party acquisitions included our 2012 acquisition of Saddle Butte Pipeline LLC’s crude oil pipeline and terminal system and natural gas gathering and processing operations in North Dakota (referred to by us as “Badlands”) and our 2015 acquisition of APL (renamed by us as Targa Pipeline Partners, L.P. or “TPL”). In these transactions we acquired (1) natural gas gathering, processing and treating assets in North Texas, West Texas, South Texas, Oklahoma, North Dakota, New Mexico and the Louisiana Gulf Coast, (2) crude oil gathering and terminal assets in North Dakota, and (3) NGL assets consisting of fractionation, transport, storage and terminaling facilities, low sulfur natural gas treating facilities (“LSNG”), pipeline transportation and distribution assets, propane storage and truck terminals primarily located near Houston, Texas and in Lake Charles, Louisiana.

 

Organic Growth Projects

 

We continue to invest significant capital to expand through organic growth projects. We have invested approximately $3.8 billion in growth capital expenditures since 2007, including approximately $0.5 billion in 2016. These expansion investments were distributed across our businesses, with 46% related to Logistics and Marketing and 54% to Gathering and Processing. We expect to continue to invest in both large and small organic growth projects in 2017. Assuming the closing of the Permian Acquisition (as defined below) occurs in the first quarter of 2017, we currently estimate that we will invest at least $700 million in growth capital expenditures (exclusive of outlays for business acquisitions) for announced projects in 2017.

Volatility of Commodity Prices

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development and production of new oil and natural gas reserves. Drilling and production activity generally decreases as crude oil and natural gas prices decrease below commercially acceptable levels. Prices of oil, natural gas and NGLs have been volatile, and we expect this volatility to continue. Our operations are affected by the level of crude, natural gas and NGL prices, the relationship among these prices and related reduced activity levels from our customers. Beginning in the fourth quarter of 2014, oil, natural gas and NGL prices declined significantly primarily due to global supply and demand imbalances. Oil, natural gas and NGL prices continued to decline in 2015 and the first half of 2016, but have since experienced some recovery.

2016 Developments

Logistics and Marketing Segment Expansion

Cedar Bayou Fractionator Train 5

 

In June 2016, we commissioned an additional fractionator, Train 5, at our 88%-owned Cedar Bayou Fractionator (“CBF”) in Mont Belvieu, Texas. This expansion added 100 MBbl/d of fractionation capacity at CBF, and is fully integrated with our existing Gulf Coast NGL storage, terminaling and delivery infrastructure, which includes an extensive network of connections to key petrochemical and industrial customers as well as our LPG export terminal at Galena Park on the Houston Ship Channel. The gross cost of Train 5 was approximately $331 million (our net cost was approximately $299 million).

 

Channelview Splitter

 

On December 27, 2015, we and an affiliate of Noble Group Ltd. (“Noble”) entered into a long-term, fee-based agreement (“Splitter Agreement”) under which Targa Terminals will build and operate a 35,000 barrel per day crude oil and condensate

5


splitter at our Channelview Terminal on the Houston Ship Channel (“Channelview Splitter”). The Channelview Splitter will have the capability to split approximately 35,000 barrels per day of crude oil and condensate into its various components, including naphtha, kerosene, gas oil, jet fuel, and liquefied petroleum gas and will provide segregated storage for the crude, condensate and components. The Channelview Splitter is expected to be completed by early 2018, and has an estimated total cost of approximately $140 million. As contemplated by the agreement entered into with Noble in December 2014 (the “December 2014 Agreement”), the Splitter Agreement completes and terminates the December 2014 Agreement, while retaining our economic benefits from that previous agreement. The first annual payment due under the Splitter Agreement was received in October 2016 and is reflected in deferred revenue as a component of other long-term liabilities on our Consolidated Balance Sheet.

Gathering and Processing Segment Expansion

 

Eagle Ford Shale Natural Gas Gathering and Processing Joint Ventures

 

In October 2015, we announced that we had entered into joint venture agreements with Sanchez Energy Corporation (“Sanchez”) to construct a new 200MMcf/d cryogenic natural gas processing plant in La Salle County, Texas (the “Raptor Plant”) and approximately 45 miles of associated pipelines. In July 2016, Sanchez sold its interest in the gathering joint venture to Sanchez Production Partners L.P. (“SPP”) and in November 2016 sold its interest in the processing joint venture to SPP. We own a 50% interest in the plant and the approximately 45 miles of high pressure gathering pipelines that will connect Sanchez's Catarina gathering system to the plant. We hold a portion of the transportation capacity on the pipeline, and the gathering joint venture receives fees for transportation. We expect to invest approximately $125 million of growth capital expenditures related to the joint ventures.

 

The Raptor Plant will accommodate the growing production from Sanchez’s premier Eagle Ford Shale acreage position in Dimmit, La Salle and Webb Counties, Texas and from other third party producers. The plant and high pressure gathering lines are supported by long-term, firm, fee-based contracts and acreage dedications with Sanchez. We will manage construction and operations of the plant and high pressure gathering lines, while the plant is expected to begin operations late in the first quarter of 2017 and to be fully operational in April 2017. Prior to the plant being placed in service, we benefit from Sanchez natural gas volumes that are processed at our Silver Oak facilities in Bee County, Texas.

 

Permian Basin Buffalo Plant

 

In April 2016, we commenced commercial operations of a new 200 MMcf/d cryogenic processing plant, known as the Buffalo Plant, in our WestTX system. This project also included the laying of new high and low pressure gathering lines in Martin and Andrews counties of Texas. Total growth capital expenditures for the Buffalo Plant were approximately $140 million (our net growth capital expenditures were approximately $102 million). The addition of the Buffalo Plant positions us to handle increasing production from our joint venture partner in WestTX, Pioneer (the largest active driller in the Spraberry and Wolfberry Trends), and from other active producers in the area.

 

Purchase of Versado Membership Interest

 

In October 2016, we acquired the remaining membership interest in Versado Gas Processors, L.L.C. (“Versado”) that we did not own. Targa held a 63% controlling interest in Versado prior to this transaction and already reported Versado on a consolidated basis. Versado consists of the Saunders, Eunice and Monument gas processing plants and related gathering systems in Southeastern New Mexico and in West Texas. Versado includes approximately 3,600 miles of natural gas gathering pipelines.

 

Additional WestTX System Processing Capacity

 

In November 2016, we announced plans to restart the currently idled 45 MMcf/d Benedum cryogenic processing plant and to add 20 MMcf/d of capacity at our Midkiff plant in our WestTX system.  The Benedum Plant was idled in September 2014 after the start-up of the 200 MMcf/d Edward Plant.  The addition of 20 MMcf/d of capacity at our Midkiff plant will increase overall plant capacity of the Midkiff/Consolidator plant complex in Reagan County, Texas from 210 MMcf/d to 230 MMcf/d. Also in November 2016, we announced plans to build a new 200 MMcf/d cryogenic processing plant in WestTX (the “Joyce Plant”). The Joyce Plant is expected to be completed in early 2018.

In addition to the major projects noted above, we had other growth capital expenditures in 2016 and expect to have more in 2017 related to the continued build out of our gathering and processing infrastructure and logistics capabilities. We will continue to evaluate

6


other potential projects based on return profile, capital requirements and strategic need and may choose to defer projects depending on expected activity levels.

 

Permian Acquisition

On January 22, 2017, we entered into definitive agreements to purchase 100% of the membership interests of Outrigger Delaware Operating, LLC, Outrigger Southern Delaware Operating, LLC (together “Outrigger Delaware”) and Outrigger Midland Operating, LLC (“Outrigger Midland” and together with “Outrigger Delaware”, “Outrigger”) (the “Permian Acquisition”).

Outrigger Delaware’s gas gathering and processing and crude gathering systems are located in Loving, Winkler and Ward counties. The operations are backed by producer dedications of more than 145,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 14 years. Outrigger Delaware’s assets include 70 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the Outrigger Delaware system.

Outrigger Midland’s gas gathering and processing and crude gathering systems are located in Howard, Martin and Borden counties. The operations are backed by producer dedications of more than 105,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 13 years. Outrigger Midland currently has 10 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the Outrigger Midland system.

We anticipate connecting Outrigger Delaware to our existing Sand Hills system and Outrigger Midland to our existing WestTX system during 2017, creating operational and capital synergies. We currently expect to close the transaction during the first quarter of 2017, subject to customary regulatory approvals and closing conditions.

 

 

Financing Activities

During the year ended December 31, 2016, we repurchased a portion of our outstanding senior notes on the open market, paying $534.3 million plus accrued interest to repurchase $559.2 million of the notes. The repurchases resulted in a $21.4 million net gain, which included the write-off of $3.5 million in related debt issuance costs. We may retire or purchase various series of the outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

In October 2016, we issued $500.0 million of 5⅛% Senior Notes due February 2025 and $500.0 million of 5⅜% Senior Notes due February 2027 (collectively, the “2016 Senior Notes”), yielding net proceeds of approximately $496.2 million and $496.2 million, respectively. The net proceeds from the offering of the 2016 Senior Notes (the “October 2016 Offering”), along with borrowings under our senior secured revolving credit facility (the “TRP Revolver”) were used to fund tender offers (the “Tender Offers”) for our 5% Senior Notes due January 2018 (the “5% Notes”), 6⅝% Senior Notes due October 2020 (the “6⅝% Notes”) and 6⅞% Senior Notes due February 2021 (the “6⅞% Notes” and together with the 5% Notes and 6⅝% Notes, the “Tender Notes”) and to fund redemption payments for the 6⅝% Notes and the 6⅞% Notes and the 6⅝%  Senior Notes of Targa Pipeline Partners due October 2020 (the “6⅝%  TPL Notes”).

 

The Tender Offers were fully subscribed and we accepted for purchase all Tender Notes that were validly tendered as of the early tender date which totaled $1,138.3 million and we recorded a loss due to debt extinguishment of approximately $59.2 million comprised of the $41.8 million premium paid, the write-off of $5.8 million of debt issuance costs, $15.1 million of debt discounts and $3.5 million of debt premiums. The aggregate principal amount of the notes redeemed following completion of the Tender Offers totaled $146.2 million and we recorded a loss due to debt extinguishment of approximately $9.7 million comprised of the $4.9 million premium paid, and a write-off of $1.1 million of debt issuance costs, $4.2 million of debt discounts and $0.5 million of debt premiums.

 

In October 2016, we entered into the Second Amendment and Restatement Agreement (the “Restatement”) to effectuate the Third Amended and Restated Credit Agreement (the “TRP Credit Agreement”). The TRP Credit Agreement amended and restated the TRP Revolver to extend the maturity date from October 2017 to October 2020. The available commitments under the TRP Revolver of $1.6 billion remained unchanged while our ability to request additional commitments increased from up to $300.0 million to up to $500.0 million. The TRP Revolver continues to bear interest costs that are dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA, and the covenants also remained substantially the same. The TRP Credit Agreement designates TPL and certain of its subsidiaries as Restricted Subsidiaries and provides for certain changes to occur upon the Partnership receiving an investment grade credit rating from Moody’s or S&P, including the release of the security interests in all collateral at the request of the Partnership.

7


 

Subsequent to entering into the TRP Credit Agreement, we executed supplemental indentures relating to all of our outstanding series of Senior Notes to designate TPL and certain of its subsidiaries as guarantors of the Senior Notes.

 

In December 2016, we amended our account receivable securitization facility to extend the maturity to December 8, 2017 and to increase the facility size to $275.0 million from $225.0 million.

 

Growth Drivers

 

We believe that our near-term growth will be driven by the level of producer activity in the basins where our gathering and processing infrastructure is located and by the level of demand for services for our Downstream Business. We believe our assets are not easily duplicated, and in the current commodity price environment, are located in many of the most attractive and active areas of exploration and production activity and are near key markets and logistics centers. Over the longer term, we expect our growth will continue to be driven by the strong position of our quality assets which will benefit from production from shale plays and by the deployment of shale exploration and production technologies in both liquids-rich natural gas and crude oil resource plays that will also provide additional opportunities for our Downstream Business. We expect that third-party acquisitions will also continue to be a focus of our growth strategy.

 

Attractive Asset Positions

 

We believe that our positioning in some of the most attractive basins will allow us to capture increased natural gas supplies for processing. Producers continue to focus drilling activity on their most attractive acreage, especially in the Permian Basin where we have a large and well positioned footprint, and are benefiting from increasing activity as rigs have been added in the basin in and around our systems.

The development of shale and resources plays has resulted in increasing NGL supplies that continue to generate demand for our fractionation services at the Mont Belvieu market hub and for LPG export services at our Galena Park Marine Terminal on the Houston Ship Channel. Since 2010, in response to increasing demand we added 278 MBbl/d of additional fractionation capacity with the additions of CBF Trains 3, 4 and 5. We believe that the higher volumes of fractionated NGLs will also result in increased demand for other related fee-based services provided by our Downstream Business. Continued demand for fractionation capacity is expected to lead to other growth opportunities.

As domestic producers have focused their drilling in crude oil and liquids-rich areas, new gas processing facilities are being built to accommodate liquids-rich gas, which results in an increasing supply of NGLs. As drilling in these areas continues, supply of NGLs requiring transportation and fractionation to market hubs is expected to continue. As the supply of NGLs increases, our integrated Mont Belvieu and Galena Park Marine Terminal assets allow us to provide the raw product, fractionation, storage, interconnected terminaling, refrigeration and ship loading capabilities to support exports by third party customers.

 

Drilling and production activity from liquids-rich natural gas shale plays and similar crude oil resource plays

 

We are actively pursuing natural gas gathering and processing and NGL fractionation opportunities associated with liquids-rich natural gas from shale and other resource plays and are also actively pursuing crude gathering and natural gas gathering and processing and NGL fractionation opportunities from active crude oil resource plays. We believe that our leadership position in the Downstream Business, which includes our fractionation and export services, provides us with a competitive advantage relative to other gathering and processing companies without these capabilities.

 

Bakken Shale / Three Forks opportunities

 

Although lower commodity prices have reduced producer activity in the Bakken Shale and Three Forks plays in the Williston Basin, we largely maintained our volumes of crude oil gathered and natural gas gathered and processed in 2016 by continuing to expand our infrastructure to capture additional volumes from wells that have already been drilled and that can be connected to our system.

 

Eagle Ford opportunities

 

As a result of our joint venture agreements with Sanchez in South Texas to construct a new 200 MMcf/d cryogenic processing plant and the associated infrastructure to connect to the Sanchez Catarina gathering system, we benefitted from increasing Sanchez production in the Eagle Ford play at our Silver Oak facilities. We expect to continue to benefit from increasing production at the Raptor Plant after the Raptor Plant is fully operational in April 2017.

 

 

8


Third party acquisitions

 

While our growth through 2010 was primarily driven by the implementation of a focused drop down strategy, we have a record of completing third party acquisitions. Since our formation, our strategy included approximately $13.1 billion in acquisitions and growth capital expenditures of which approximately $6.2 billion was for acquisitions from, or of, third parties. Additionally, we announced the Permian Acquisition in January 2017. We expect that third-party acquisitions will continue to be a focus of our growth strategy.

 

Competitive Strengths and Strategies

 

We believe that we are well positioned to execute our business strategies due to the following competitive strengths:

 

Strategically located gathering and processing asset base

 

Our gathering and processing businesses are strategically located in generally attractive oil and gas producing basins and are well positioned within each of those basins. Activity in the shale resource plays underlying our gathering assets is driven by the economics of oil, condensate, gas and NGL production from the particular reservoirs in each play. Activity levels for most of our gathering and processing asset are driven primarily by liquid hydrocarbon commodity prices. If drilling and production activities in these areas continue, we would likely increase the volumes of natural gas and crude oil available to our gathering and processing systems.

 

Leading fractionation, LPG export and NGL infrastructure position

 

We are one of the largest fractionators of NGLs in the Gulf Coast. Our fractionation assets are primarily located in Mont Belvieu, Texas and to a lesser extent Lake Charles, Louisiana, which are key market centers for NGLs. Our logistics operations at Mont Belvieu, the major U.S. hub of NGL infrastructure, include connection to a number of mixed NGL (“mixed NGLs” or “Y-grade”) supply pipelines, storage, interconnection and takeaway pipelines and other transportation infrastructure. Our logistics assets, including fractionation facilities, storage wells, low ethane propane de-ethanizer, and our Galena Park Marine Terminal and related pipeline systems and interconnects, are also located near and connected to key consumers of NGL products including the petrochemical and industrial markets. The location and interconnectivity of these assets are not easily replicated, and we have additional capability to expand their capacity. We have extensive experience in operating these assets and developing, permitting and constructing new midstream assets.

 

Comprehensive package of midstream services

 

We provide a comprehensive package of services to natural gas and crude oil producers. These services are essential to gather crude and to gather, process and treat wellhead gas to meet pipeline standards and to extract NGLs for sale into petrochemical, industrial, commercial and export markets. We believe that our ability to provide these integrated services provides an advantage in competing for new supplies because we can provide substantially all of the services producers, marketers and others require for moving natural gas and NGLs from wellhead to market on a cost-effective basis. Additionally, we believe the barriers to enter the midstream sector on a scale similar to ours are reasonably high due to the high cost of replicating or acquiring assets in key strategic positions, the difficulty of permitting and constructing new midstream assets and the difficulty of developing the expertise necessary to operate them.

 

High quality and efficient assets

 

Our gathering and processing systems and logistics assets consist of high-quality, well-maintained facilities, resulting in low-cost, efficient operations. Advanced technologies have been implemented for processing plants (primarily cryogenic units utilizing centralized control systems), measurements (essentially all electronic and electronically linked to a central data-base) and operations and maintenance to manage work orders and implement preventative maintenance schedules (computerized maintenance management systems). These applications have allowed proactive management of our operations resulting in lower costs and minimal downtime. We have established a reputation in the midstream industry as a reliable and cost-effective supplier of services to our customers and have a track record of safe, efficient, and reliable operation of our facilities. We will continue to pursue new contracts, cost efficiencies and operating improvements of our assets. Such improvements in the past have included new production and acreage commitments, reducing fuel gas and flare volumes and improving facility capacity and NGL recoveries. We will also continue to optimize existing plant assets to improve and maximize capacity and throughput.

 

In addition to routine annual maintenance expenses, our maintenance capital expenditures have averaged approximately $83.2 million per year over the last four years. We believe that our assets are well-maintained and anticipate that a similar level of maintenance capital expenditures will be sufficient for us to continue to operate our existing assets in a prudent, safe and cost-effective manner.

 

 

9


Large, diverse business mix with favorable contracts and increasing fee-based business

 

We maintain gas gathering and processing positions in strategic oil and gas producing areas across multiple basins and provide these and other services under attractive contract terms to a diverse mix of customers across our areas of operation. Consequently, we are not dependent on any one oil and gas basin or customer. Our Logistics and Marketing assets are typically located near key market hubs and near most of our NGL customers. They also serve must-run portions of the natural gas value chain, are primarily fee-based and have a diverse mix of customers.  

 

Our contract portfolio has attractive rate and term characteristics including a significant fee-based component, especially in our Downstream Business. Our expected continued growth of the fee-based Downstream Business may result in increasing fee-based cash flow. Closing the Permian Acquisition will also result in increasing fee-based cash flow as the entities acquired have primarily fee-based gathering and processing contracts.

 

Financial flexibility

 

We have historically maintained a conservative leverage ratio and ample liquidity and have funded our growth investments with a mix of equity and debt over time. Disciplined management of leverage, liquidity and commodity price volatility allow us to be flexible in our long-term growth strategy and enable us to pursue strategic acquisitions and large growth projects.

 

Experienced and long-term focused management team

 

Our current executive management team includes a number of individuals who formed us in 2004, and several others who managed many of our businesses prior to acquisition by Targa. They possess a breadth and depth of experience working in the midstream energy business. Other officers and key operational, commercial and financial employees have significant experience in the industry and with our assets and businesses.

 

Attractive cash flow characteristics

 

We believe that our strategy, combined with our high-quality asset portfolio, allows us to generate attractive cash flows. Geographic, business and customer diversity enhances our cash flow profile. Our Gathering and Processing segment has a contract mix that is primarily percent-of-proceeds, but also has increasing components of fee-based revenues driven by fees added to percent-of-proceeds contracts for natural gas treating and compression, by new/amended contracts with a combination of percent-of-proceeds and fee-based components and by essentially fully fee-based crude oil gathering and gas gathering and processing in certain areas where fee-based contracts are prevalent such as the Williston Basin and SouthTX. Contracts in our Coastal Gathering and Processing segment are primarily hybrid (percent-of-liquids with a fee floor) or percent-of-liquids contracts. Contracts in the Downstream Business are predominately fee-based based on volumes and contracted rates, with a large take-or-pay component. Our contract mix, along with our commodity hedging program, serves to mitigate the impact of commodity price movements on cash flow.

 

We have hedged the commodity price risk associated with a portion of our expected natural gas, NGL and condensate equity volumes and future commodity purchases and sales through 2019 by entering into financially settled derivative transactions. These transactions include swaps, futures, purchased puts (or floors) and costless collars. The primary purpose of our commodity risk management activities is to hedge our exposure to price risk and to mitigate the impact of fluctuations in commodity prices on cash flow. We have intentionally tailored our hedges to approximate specific NGL products and to approximate our actual NGL and residue natural gas delivery points. Although the degree of hedging will vary, we intend to continue to manage some of our exposure to commodity prices by entering into similar hedge transactions. We also monitor and manage our inventory levels with a view to mitigate losses related to downward price exposure.

 

Asset base well-positioned for organic growth

 

We believe that our asset platform and strategic locations allow us to maintain and potentially grow our volumes and related cash flows as our supply areas benefit from continued exploration and development over time. Technology advances have resulted in increased domestic oil and liquids-rich gas drilling and production activity. While recent commodity price levels have impacted activity, the location of our assets provides us with access to natural gas and crude oil supplies and proximity to end-user markets and liquid market hubs while positioning us to capitalize on drilling and production activity in those areas. Our existing infrastructure has the capacity to handle some incremental increases in volumes without significant investments as well as opportunities to leverage existing assets with meaningful expansions. We believe that as domestic supply and demand for natural gas, crude oil and NGLs, and services for each grows over the long term, our infrastructure will increase in value as such infrastructure takes on increasing importance in meeting that growing supply and demand.

 

While we have set forth our strategies and competitive strengths above, our business involves numerous risks and uncertainties which

10


may prevent us from executing our strategies. These risks include the adverse impact of changes in natural gas, NGL and condensate/crude oil prices, the supply of or demand for these commodities, and our inability to access sufficient additional production to replace natural declines in production. For a more complete description of the risks associated with an investment in us, see “Item 1A. Risk Factors.”

 

Relationship with Targa

 

Targa has used us as a growth vehicle to pursue the acquisition and expansion of midstream natural gas, NGL, crude oil and other complementary energy businesses and assets as evidenced by our acquisitions of businesses from Targa. However, Targa is not prohibited from competing with us and may evaluate acquisitions and dispositions that do not involve us. In addition, through our relationship with Targa, we have access to a significant pool of management talent, strong commercial relationships throughout the energy industry and access to Targa’s broad operational, commercial, technical, risk management and administrative infrastructure.

 

As a result of the TRC/TRP Merger, which was completed on February 17, 2016, Targa owns all of the outstanding TRP common units as well as a 2% general partner interest in the Partnership. On October 19, 2016, TRP executed the Third Amended and Restated Agreement of Limited Partnership (the “Third A&R Partnership Agreement”), effective as of December 1, 2016. The Third A&R Partnership Agreement (i) eliminated the incentive distribution rights (“IDRs”) held by the General Partner, and related distribution and allocation provisions, (ii) eliminated the special general partner interest in the Partnership (the “Special GP Interest”) held by the General Partner, (iii) provided the ability to declare monthly distributions in addition to quarterly distributions, (iv) modified certain provisions relating to distributions from available cash, (v) eliminated the Class B Unit provisions (as defined in the Third A&R Partnership Agreement) and (vi) made changes to reflect the passage of time and removed provisions that were no longer applicable.

 

In connection with the Third A&R Partnership Agreement, TRP issued to the General Partner (i) 20,380,286 common units and 424,590 General Partner units in exchange for the cancellation of the IDRs and (ii) 11,267,485 common units and 234,739 General Partner units in exchange for cancellation of the Special GP Interest. These common units and General Partner units were issued on December 1, 2016 pursuant to the exemption offered by Section 4(a)(2) of the Securities Exchange Act of 1934. The Partnership Agreement with us governs our relationship regarding certain reimbursement and indemnification matters. See “Item 13. Certain Relationships and Related Transactions and Director Independence.”

 

We do not have any employees to carry out our operations. Targa employs approximately 1,970 people. See “—Employees.” Targa charges us for all the direct costs of the employees assigned to our operations, as well as all general and administrative support costs other than its direct support costs of being a separate reporting company and its cost of providing management and support services to certain unaffiliated spun-off entities. We generally reimburse Targa for cost allocations to the extent that they have required a current cash outlay by Targa.

 

Our Challenges

 

We face a number of challenges in implementing our business strategy. For example:

 

 

We have a substantial amount of indebtedness which may adversely affect our financial position.

 

 

Our cash flow is affected by supply and demand for crude oil, natural gas and NGL products and by natural gas, NGL and condensate prices, and decreases in these prices could adversely affect our results of operations and financial condition.

 

 

Our growth strategy requires access to new capital. Volatile capital markets with uncertain access or increased competition for investment opportunities could impair our ability to grow.

 

 

Our long-term success depends on our ability to obtain new sources of supplies of natural gas, crude oil and NGLs, which is subject to certain factors beyond our control. Any decrease in supplies of natural gas, crude oil or NGLs could adversely affect our business and operating results.

 

 

Although we believe we have a large, diverse customer base, we are subject to counterparty risk which could adversely affect our financial position.

 

 

Our hedging activities may not be effective in reducing the variability of our cash flows and may, in certain circumstances, increase the variability of our cash flows.

 

 

If we do not successfully make acquisitions on economically acceptable terms or efficiently and effectively integrate assets from acquisitions, our results of operations and financial condition could be adversely affected.

 

11


 

We are subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

 

 

Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

 

For a further discussion of these and other challenges we face, please read “Item 1A. Risk Factors.”

 

 

 

Our Business Operations

 

Our operations are reported in two segments: (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business).

 

Gathering and Processing Segment

 

Our Gathering and Processing segment consists of gathering, compressing, dehydrating, treating, conditioning, processing, and marketing natural gas and gathering crude oil. The gathering of natural gas consists of aggregating natural gas produced from various wells through small diameter gathering lines to processing plants. Natural gas has a widely varying composition depending on the field, the formation and the reservoir from which it is produced. The processing of natural gas consists of the extraction of imbedded NGLs and the removal of water vapor and other contaminants to form (i) a stream of marketable natural gas, commonly referred to as residue gas, and (ii) a stream of mixed NGLs. Once processed, the residue gas is transported to markets through pipelines that are owned by either the gatherers and processors or third parties. End-users of residue gas include large commercial and industrial customers, as well as natural gas and electric utilities serving individual consumers. We sell our residue gas either directly to such end-users or to marketers into intrastate or interstate pipelines, which are typically located in close proximity or with ready access to our facilities. The gathering of crude oil consists of aggregating crude oil production primarily through gathering pipeline systems, which deliver crude oil to a combination of other pipelines, rail and truck.

 

We continually seek new supplies of natural gas and crude oil, both to offset the natural decline in production from connected wells and to increase throughput volumes. We obtain additional natural gas and crude oil supply in our operating areas by contracting for production from new wells or by capturing existing production currently gathered by others. Competition for new natural gas and crude oil supplies is based primarily on location of assets, commercial terms including pre-existing contracts, service levels and access to markets. The commercial terms of natural gas gathering and processing arrangements and crude oil gathering are driven, in part, by capital costs, which are impacted by the proximity of systems to the supply source and by operating costs, which are impacted by operational efficiencies, facility design and economies of scale.

 

We believe our extensive asset base and scope of operations in the regions in which we operate provide us with significant opportunities to add both new and existing natural gas and crude oil production to our systems. We believe our size and scope give us a strong competitive position through close proximity to a large number of existing and new producing wells in our areas of operations, allowing us to generate economies of scale and to provide our customers with access to our existing facilities and to end-use markets and market hubs. Additionally, we believe our ability to serve our customers’ needs across the natural gas and NGL value chain further augments our ability to attract new customers.

 

The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma and South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

 

The natural gas processed in this segment is supplied through our gathering systems which, in aggregate, consist of approximately 27,000 miles of natural gas pipelines and include 36 owned and operated processing plants. During 2016, we processed an average of 3,412.0 MMcf/d of natural gas and produced an average of 305.5 MBbl/d of NGLs. In addition to our natural gas gathering and processing, our Badlands operations include a crude oil gathering system and four terminals with crude oil operational storage capacity of 125 MBbl.

 

We believe we are well positioned as a gatherer and processor in the Permian Basin, Eagle Ford Shale, Barnett Shale, Anadarko, Ardmore, Arkoma and Williston Basins. We believe proximity to production and development activities allows us to compete for new supplies of natural gas and crude oil partially because of our lower competitive cost to connect new wells and to process additional natural gas in our existing processing plants and because of our reputation for reliability. Additionally, because we operate all the plants in these basins we are often able to redirect natural gas among our processing plants, which are often interconnected in these

12


regions, providing operational flexibility and allowing us to optimize processing efficiency and further improve the profitability of our operations.

 

The Gathering and Processing segment’s operations consist of SAOU, WestTX, Sand Hills, Versado, SouthTX, North Texas, SouthOK, WestOK, Coastal and Badlands each as described below:

 

SAOU

 

SAOU includes approximately 1,700 miles of pipelines in the Permian Basin that gather natural gas for delivery to the Mertzon, Sterling, Conger and High Plains processing plants. SAOU is connected to thousands of producing wells and over 840 central delivery points. SAOU’s processing facilities are refrigerated cryogenic processing plants with an aggregate processing capacity of approximately 369 MMcf/d. These plants have residue gas connections to pipelines owned by affiliates of Atmos Energy Corporation (“Atmos”), Enterprise Products Partners L.P. (“EPD”), Kinder Morgan, Inc. (“Kinder Morgan”), Northern Natural Gas Company (“Northern”) and ONEOK, Inc. (“ONEOK”). SAOU has gathering lines that extend across nine counties.

 

WestTX

 

The WestTX gathering system has approximately 4,400 miles of natural gas gathering pipelines located across nine counties within the Permian Basin in West Texas. We have an approximate 72.8% ownership in the WestTX system. Pioneer, the largest active driller in the Spraberry and Wolfberry Trends and a major producer in the Permian Basin, owns the remaining interest in the WestTX system.

 

The WestTX system includes six separate plants: the Consolidator, Driver, Midkiff, Benedum, Edward and Buffalo processing facilities. The WestTX processing operations have an aggregate processing name-plate capacity of approximately 855 MMcf/d.

 

The WestTX system has access to natural gas take-away pipelines owned by Atmos; El Paso Natural Gas Company; Kinder Morgan; Oneok West Texas, Enterprise Interstate, LLC; and Northern.

 

Sand Hills

 

The Sand Hills operations consist of the Sand Hills and Puckett gathering systems in West Texas. These systems consist of approximately 1,600 miles of natural gas gathering pipelines. These gathering systems are primarily low-pressure gathering systems with significant compression assets. The Sand Hills refrigerated cryogenic processing plant has a gross processing capacity of 165 MMcf/d and residue gas connections to pipelines owned by affiliates of EPD, Kinder Morgan and ONEOK.

 

Versado

 

Versado consists of the Saunders, Eunice and Monument gas processing plants and related gathering systems in Southeastern New Mexico and in West Texas. Versado includes approximately 3,600 miles of natural gas gathering pipelines. The Saunders, Eunice and Monument refrigerated cryogenic processing plants have aggregate processing capacity of 255 MMcf/d. These plants have residue gas connections to pipelines owned by affiliates of Kinder Morgan and MidAmerican Energy Company.

 

SouthTX

 

The SouthTX gathering system includes approximately 800 miles of gathering pipelines located in the Eagle Ford Shale in southern Texas. Included in the total SouthTX pipeline mileage is our 75% interest in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”), which has approximately 60 miles of gathering pipelines, and our 50% interest in T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford”), which has approximately 120 miles of gathering pipelines. T2 LaSalle and T2 Eagle Ford are operated by a subsidiary of Southcross Holdings, L.P. (“Southcross”), which owns the remaining interests.

 

The SouthTX assets also include a 50% interest in T2 EF Cogeneration Holdings L.L.C. (“T2 Cogen”, together with T2 LaSalle and T2 Eagle Ford, the “T2 Joint Ventures”), which owns a cogeneration facility. T2 Cogen is operated by Southcross, which owns the remaining interest in T2 Cogen.

 

The SouthTX system processes natural gas through the Silver Oak I and II processing plants. The Silver Oak I and II facilities are each 200 MMcf/d cryogenic plants located in Bee County, Texas. We own 90% of the Silver Oak II processing plant and SPP owns the remaining interest. The SouthTX system includes our 50% interest in Carnero Gathering, LLC and our 50% interest in Carnero Processing, LLC (together, the “Carnero Joint Ventures”). SPP owns the remaining interest in the Carnero Joint Ventures. The Carnero Joint Ventures were formed in October 2015 for the purposes of constructing a 200 MMcf/d cryogenic plant and approximately 45 miles of high pressure gathering pipelines. As of December 31, 2016, the processing plant is under construction

13


while the Carnero gathering facilities are operational and connect with SPP’s Catarina gathering system. We operate the Carnero gathering facilities and will operate the Carnero processing facility when complete.

 

The SouthTX system has access to natural gas take-away pipelines owned by Enterprise Intrastate, LLC; Kinder Morgan; Tejas Pipeline LLC, Natural Gas Pipeline Company of America; Tennessee Gas Pipeline Company, LLC; Transcontinental Gas Pipe Line, CPS Energy, and Houston Pipe Line Company LP.

 

North Texas

 

North Texas includes two interconnected gathering systems in the Fort Worth Basin, including gas from the Barnett Shale and Marble Falls plays, with approximately 4,600 miles of pipelines gathering wellhead natural gas for the Chico, Shackelford and Longhorn natural gas processing facilities. These plants have residue gas connections to pipelines owned by affiliates of Atmos, Energy Transfer Fuel LP and EPD.

 

The Chico gathering system consists of approximately 2,550 miles of gathering pipelines located in the Denton, Montague, Wise and Clay Counties in North Texas. Wellhead natural gas is either gathered for the Chico or Longhorn plants located in Wise County, Texas, and then compressed for processing, or it is compressed in the field at numerous compressor stations and then moved via one of several high-pressure gathering pipelines to the Chico or Longhorn plants. The Chico plant has an aggregated processing capacity of 265 MMcf/d and an integrated fractionation capacity of 15 MBbl/d. The Longhorn plant has a capacity of 200 MMcf/d. The Shackelford gathering system includes approximately 2,000 miles of gathering pipelines and gathers wellhead natural gas largely for the Shackelford plant in Albany, Texas. Natural gas gathered from the northern and eastern portions of the Shackelford gathering system is typically compressed in the field at numerous compressor stations and then transported to the Chico plant for processing. The Shackelford plant has an aggregate processing capacity of 13 MMcf/d.

SouthOK

The SouthOK gathering system is located in the Ardmore and Anadarko Basins and includes the Golden Trend, SCOOP, and Woodford Shale areas of southern Oklahoma. The gathering system has approximately 1,500 miles of active pipelines.

 

The SouthOK system includes six separate processing plants: Velma, Velma V-60, Coalgate, Atoka, Stonewall and Tupelo. The SouthOK processing operations have a total name-plate capacity of 580 MMcf/d. The Coalgate, Atoka and Stonewall facilities are owned by Centrahoma Processing, LLC (“Centrahoma”), a joint venture that we operate, and in which we have a 60% ownership interest; the remaining 40% ownership interest is held by MPLX, LP. The SouthOK system has access to natural gas take-away pipelines owned by Enable Oklahoma Intrastate Transmission, LLC; MPLX, LP; Natural Gas Pipeline Company of America; ONEOK and Southern Star Central Gas Pipeline, Inc.

 

WestOK

 

The WestOK gathering system is located in north central Oklahoma and southern Kansas’ Anadarko Basin and includes the Woodford shale. The gathering system expands into 13 counties with approximately 6,400 miles of natural gas gathering pipelines.

 

The WestOK system processes natural gas through three separate cryogenic natural gas processing plants, located at the Waynoka I and II and the Chester facilities, and one refrigeration plant at the Chaney Dell facility, with total name plate capacity of 465 MMcf/d. The WestOK system has access to natural gas take-away pipelines owned by Enogex LLC; Panhandle Eastern Pipe Line Company, LP; and Southern Star Central Gas Pipeline, Inc.

 

Coastal

 

Our Coastal plants process natural gas produced from shallow-water central and western Gulf of Mexico natural gas wells and from deep shelf and deep-water Gulf of Mexico production via connections to third-party pipelines or through pipelines owned by us. Our Coastal plants have access to markets across the U.S. through the interstate natural gas pipelines to which they are interconnected. The industry continues to rationalize gas processing capacity along the western Louisiana Gulf Coast with most of the producer volumes going to more efficient plants such as Targa’s Barracuda and Gillis plants.

 

LOU consists of approximately 980 miles of onshore gathering system pipelines in Southwest Louisiana. The gathering system is connected to numerous producing wells, central delivery points and/or pipeline interconnects in the area between Lafayette and Lake Charles, Louisiana. The gathering system is a high-pressure gathering system that delivers natural gas for processing to either the Acadia or Gillis plants via three main trunk lines. The processing facilities include the Gillis and Acadia processing plants, both of which are cryogenic plants. The Big Lake plant, also cryogenic, is located near the LOU gathering system. These processing plants have an aggregate processing capacity of approximately 440 MMcf/d. In addition, the Gillis plant has integrated fractionation with

14


operating capacity of approximately 11 MBbl/d which is interconnected with the Lake Charles Fractionator. The LOU gathering system is also interconnected with the Lowry gas plant, allowing receipt or delivery of gas.

 

Through our 76.8% ownership interest in Venice Energy Services Company, L.L.C. in Southeast Louisiana, we operate the Venice gas plant, which has an aggregate processing capacity of 750 MMcf/d and the Venice Gathering System (“VGS”) that is approximately 125 miles in length and has a nominal capacity of 320 MMcf/d (collectively “VESCO”). VESCO receives unprocessed gas directly or indirectly from seven offshore pipelines and gas gathering systems including the VGS system. VGS gathers natural gas from the shallow waters of the eastern Gulf of Mexico and supplies the VESCO gas plant.

 

Coastal also includes two wholly-owned and operated gas processing plants (one now idled) and three partially owned plants which are not operated by us. These plants, having an aggregate processing capacity of approximately 3,255 MMcf/d, are generally situated on mainline natural gas pipelines near the coastline and process volumes of natural gas collected from multiple offshore gathering systems and pipelines throughout the Gulf of Mexico. Coastal also has 100% ownership in two offshore gathering systems that are operated by us. The Pelican and Seahawk gathering systems have a combined length of approximately 200 miles and a combined capacity of approximately 230 MMcf/d. These systems gather natural gas from the shallow waters of the central Gulf of Mexico and supply a portion of the natural gas delivered to the Barracuda and Gillis processing facilities.

 

Badlands

 

The Badlands operations are located in the Bakken and Three Forks Shale plays of the Williston Basin in North Dakota and include approximately 400 miles of crude oil gathering pipelines, 40 MBbl of operational crude storage capacity at the Johnsons Corner Terminal, 30 MBbl of operational crude storage capacity at the Alexander Terminal, 30 MBbl of operational crude oil storage at New Town and 25 MBbl of operational crude oil storage at Stanley. The Badlands assets also includes approximately 200 miles of natural gas gathering pipelines and the Little Missouri natural gas processing plant with a gross processing capacity of approximately 90 MMcf/d.

 

The following table lists the Gathering and Processing segment’s processing plants and related volumes for the year ended December 31, 2016:

 

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Gross

 

Gross Plant

 

Gross

 

 

 

 

 

 

 

 

 

 

 

Processing

 

Natural Gas

 

NGL

 

 

Process

Operated/

 

 

 

 

 

 

 

Capacity

 

Inlet Throughput

 

Production

 

Facility

Type (5)

Non-Operated

% Owned

 

 

 

 

Location

(MMcf/d) (1)

 

Volume (MMcf/d) (2) (3) (4)

 

(MBbl/d) (2) (3) (4)

 

SAOU

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Mertzon

Cryo

Operated

 

100.0

 

 

 

 

Irion County, TX

 

52.0

 

 

 

 

 

 

 

Sterling

Cryo

Operated

 

100.0

 

 

 

 

Sterling County, TX

 

92.0

 

 

 

 

 

 

 

Conger (6)

Cryo

Operated

 

100.0

 

 

 

 

Sterling County, TX

 

25.0

 

 

 

 

 

 

 

High Plains

Cryo

Operated

 

100.0

 

 

 

 

Midland County, TX

 

200.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Area Total

 

369.0

 

 

259.1

 

 

31.8

 

WestTX (7)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidator

Cryo

Operated

 

72.8

 

 

 

 

Reagan County, TX

 

150.0

 

 

 

 

 

 

 

Midkiff (8)

Cryo

Operated

 

72.8

 

 

 

 

Reagan County, TX

 

60.0

 

 

 

 

 

 

 

Driver

Cryo

Operated

 

72.8

 

 

 

 

Midland County, TX

 

200.0

 

 

 

 

 

 

 

Benedum (9)

Cryo

Operated

 

72.8

 

 

 

 

Upton County, TX

 

45.0

 

 

 

 

 

 

 

Edward

Cryo

Operated

 

72.8

 

 

 

 

Upton County, TX

 

200.0

 

 

 

 

 

 

 

Buffalo

Cryo

Operated

 

72.8

 

 

 

 

Martin County, TX

 

200.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Area Total

 

855.0

 

 

500.7

 

 

62.7

 

Sand Hills

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sand Hills

Cryo

Operated

 

100.0

 

 

 

 

Crane County, TX

 

165.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Area Total

 

165.0

 

 

139.5

 

 

14.7

 

Versado (10)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Saunders

Cryo

Operated

 

100.0

 

 

 

 

Lea County, NM

 

60.0

 

 

 

 

 

 

 

Eunice

Cryo

Operated

 

100.0

 

 

 

 

Lea County, NM

 

110.0

 

 

 

 

 

 

 

Monument

Cryo

Operated

 

100.0

 

 

 

 

Lea County, NM

 

85.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Area Total

 

255.0

 

 

181.5

 

 

21.7

 

SouthTX

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Silver Oak I

Cryo

Operated

 

100.0

 

 

 

 

Bee County, TX

 

200.0

 

 

 

 

 

 

 

Silver Oak II

Cryo

Operated

 

90.0

 

 

 

 

Bee County, TX

 

200.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Area Total

 

400.0

 

 

216.4

 

 

23.8

 

North Texas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Chico (11)

Cryo

Operated

 

100.0

 

 

 

 

Wise County, TX

 

265.0

 

 

 

 

 

 

 

Shackelford

Cryo

Operated

 

100.0

 

 

 

 

Shackelford County, TX

 

13.0

 

 

 

 

 

 

 

Longhorn

Cryo

Operated

 

100.0

 

 

 

 

Wise County, TX

 

200.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Area Total

 

478.0

 

 

317.3

 

 

35.8

 

SouthOK (12)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Atoka (13)

Cyro

Operated

 

60.0

 

 

 

 

Atoka County, OK

 

20.0

 

 

 

 

 

 

 

Coalgate

Cryo

Operated

 

60.0

 

 

 

 

Coal County, OK

 

80.0

 

 

 

 

 

 

 

Stonewall

Cryo

Operated

 

60.0

 

 

 

 

Coal County, OK

 

200.0

 

 

 

 

 

 

 

Tupelo

Cryo

Operated

 

100.0

 

 

 

 

Coal County, OK

 

120.0

 

 

 

 

 

 

 

Velma

Cryo

Operated

 

100.0

 

 

 

 

Stephens County, OK

 

100.0

 

 

 

 

 

 

 

Velma V-60

Cryo

Operated

 

100.0

 

 

 

 

Stephens County, OK

 

60.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Area Total

 

580.0

 

 

462.1

 

 

39.4

 

WestOK (12)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Waynoka I

Cryo

Operated

 

100.0

 

 

 

 

Woods County, OK

 

200.0

 

 

 

 

 

 

 

Waynoka II

Cryo

Operated

 

100.0

 

 

 

 

Woods County, OK

 

200.0

 

 

 

 

 

 

 

Chaney Dell (14)

RA

Operated

 

100.0

 

 

 

 

Major County, OK

 

30.0

 

 

 

 

 

 

 

Chester

Cryo

Operated

 

100.0

 

 

 

 

Woodward County, OK

 

28.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Area Total

 

458.0

 

 

444.9

 

 

27.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Coastal (15)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gillis (16)

Cryo

Operated

 

100.0

 

 

 

 

Calcasieu Parish, LA

 

180.0

 

 

 

 

 

 

 

Acadia (17)

Cryo

Operated

 

100.0

 

 

 

 

Acadia Parish, LA

 

80.0

 

 

 

 

 

 

 

Big Lake (18)

Cryo

Operated

 

100.0

 

 

 

 

Calcasieu Parish, LA

 

180.0

 

 

 

 

 

 

 

VESCO (19)

Cryo

Operated

 

76.8

 

 

 

 

Plaquemines Parish, LA

 

750.0

 

 

 

 

 

 

 

Barracuda

Cryo

Operated

 

100.0

 

 

 

 

Cameron Parish, LA

 

190.0

 

 

 

 

 

 

 

Lowry (20)

Cryo

Operated

 

100.0

 

 

 

 

Cameron Parish, LA

 

265.0

 

 

 

 

 

 

 

Terrebone

RA

Non-operated

 

3.2

 

 

 

 

Terrebonne Parish, LA

 

950.0

 

 

 

 

 

 

 

Toca

Cryo/RA

Non-operated

 

12.6

 

 

 

 

St. Bernard Parish, LA

 

1,150.0

 

 

 

 

 

 

 

Sea Robin

Cryo

Non-operated

 

0.8

 

 

 

 

Vermillion Parish, LA

 

700.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Area Total

 

4,445.0

 

 

838.4

 

 

41.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Badlands

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Little Missouri (21)

Cryo/RA

Operated

 

100.0

 

 

 

 

McKenzie County, ND

 

90.0

 

 

52.1

 

 

7.3

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Segment System Total

 

8,095.0

 

 

3,412.0

 

 

305.5

 

       _______________

 

16


 

(1)

Gross processing capacity represents 100% of ownership interests and may differ from nameplate processing capacity due to multiple factors including items such as compression limitations, and quality and composition of the gas being processed.

 

(2)

Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of the natural gas processing plant, except for Badlands which represents the total wellhead gathered volume.

 

(3)

Plant natural gas inlet and NGL production volumes represent 100% of ownership interests for our consolidated VESCO joint venture, Silver Oak II, Atoka, Coalgate and Stonewall plants and our ownership share of volumes for other partially owned plants that we proportionately consolidate based on our ownership interest which is adjustable subject to an annual redetermination based on our proportionate share of plant production.

 

(4)

Per day Gross Plant Natural Gas Inlet and NGL Production statistics for plants listed above are based on the number of days operational during 2016.

 

(5)

Cryo – Cryogenic Processing; RA – Refrigerated Absorption Processing.

 

(6)

The Conger plant was idled due to market conditions in September 2014.

 

(7)

Gross plant natural gas inlet throughput volumes and gross NGL production volumes for WestTX are presented on a pro-rata net basis representing our undivided ownership interest in WestTX, which we proportionately consolidate in our financial statements.

 

(8)

In November 2016, we announced plans to add 20 MMcf/d of capacity at our Midkiff plant.

 

(9)

In November 2016, we announced plans to restart the idled Benedum plant.

 

(10)

Includes throughput other than plant inlet, primarily from compressor stations.

 

(11)

The Chico plant has fractionation capacity of approximately 15 MBbl/d.

 

(12)

Certain processing facilities in these business units are capable of processing more than their name-plate capacity and when capacity is exceeded the facilities will off-load volumes to other processors, as needed. The gross plant natural gas inlet throughput volume includes these off-loaded volumes.

 

(13)

The Atoka plant was idled due to the start-up of the Stonewall plant in May 2014.

 

(14)

The Chaney Dell plant was idled in December 2015 due to lower volumes in the WestOK system.

 

(15)

Coastal also includes three offshore gathering systems which have a combined length of approximately 325 miles.

 

(16)

The Gillis plant has fractionation capacity of approximately 11 MBbl/d.

 

(17)

The Acadia plant is available and operates on the LOU system as market conditions allow.

 

(18)

The Big Lake plant is available and operates as market conditions allow.

 

(19)

VESCO also includes an offshore gathering system with a combined length of approximately 125 miles.

 

(20)

The Lowry facility was idled in June 2015, but is available as market conditions allow.

 

(21)

Little Missouri Trains I and II are Straight Refrigeration plants and Little Missouri Train III is a Cryo plant.

 

Logistics and Marketing Segment

 

Our Logistics and Marketing segment is also referred to as our Downstream Business. Our Downstream Business includes the activities necessary to convert mixed NGLs into NGL products and provides certain value-added services such as the fractionation, storage, terminaling, transportation, exporting, distribution and marketing of NGLs and NGL products; the storing and terminaling of refined petroleum products and crude oil; and certain natural gas supply and marketing activities in support of our other businesses, as well as transporting natural gas and NGLs. These assets are generally connected to and supplied in part by our Gathering and Processing segment and are predominantly located in Mont Belvieu and Galena Park, Texas, in Lake Charles, Louisiana, in Tacoma, Washington and in Baltimore, Maryland.

 

The Logistics and Marketing segment covers activities required to distribute and market raw and finished NGLs and all natural gas marketing activities. It includes (1) marketing our own NGL production and purchasing NGL products for resale in selected United States markets; (2) providing LPG balancing services to refinery customers; (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end-users; (4) providing propane, butane and services to LPG exporters; and (5) marketing natural gas available to us from our Gathering and Processing segment and the purchase and resale and other value added activities related to third-party natural gas in selected United States markets.

 

The Logistics and Marketing segment also transports, distributes and markets NGLs via terminals and transportation assets across the U.S. We own or commercially manage terminal facilities in a number of states, including Texas, Oklahoma, Louisiana, Arizona, Nevada, California, Florida, Alabama, Mississippi, Tennessee, Kentucky, New Jersey and Washington. The geographic diversity of our assets provide direct access to many NGL customers as well as markets via trucks, barges, ships, rail cars and open-access regulated NGL pipelines owned by third parties.

 

The Logistics and Marketing segment consists of assets and business activities associated with: Fractionation, NGL Storage and Terminaling, Petroleum Logistics, NGL Distribution and Marketing, Wholesale Domestic Marketing, Refinery Services, Commercial Transportation and Natural Gas Marketing.

 

Fractionation

 

After being extracted in the field, mixed NGLs, sometimes referred to as “Y-grade” or “raw NGL mix,” are typically transported to a centralized facility for fractionation where the mixed NGLs are separated into discrete NGL products: ethane, ethane-propane mix, propane, normal butane, iso-butane and natural gasoline.

 

Our NGL fractionation business is under fee-based arrangements. These fees are subject to adjustment for changes in certain fractionation expenses, including energy costs. The operating results of our NGL fractionation business are dependent upon the volume of mixed NGLs fractionated, the level of fractionation fees charged and product gains/losses from fractionation.

 

17


We believe that sufficient volumes of mixed NGLs will be available for fractionation in commercially viable quantities for the foreseeable future due to historical increases in NGL production from shale plays and other shale-technology-driven resource plays in areas of the U.S. that include North Texas, South Texas, the Permian Basin, Oklahoma and the Rockies and certain other basins accessed by pipelines to Mont Belvieu, as well as from conventional production of NGLs in areas such as the Permian Basin, Mid-Continent, East Texas, South Louisiana and shelf and deep-water Gulf of Mexico. Hydrocarbon dew point specifications implemented by individual natural gas pipelines and the Policy Statement on Provisions Governing Natural Gas Quality and Interchangeability in Interstate Natural Gas Pipeline Company Tariffs enacted in 2006 by the Federal Energy Regulatory Commission (“FERC”) should result in volumes of mixed NGLs being available for fractionation because natural gas requires processing or conditioning to meet pipeline quality specifications. These requirements establish a base volume of mixed NGLs during periods when it might be otherwise uneconomical to process certain sources of natural gas. Furthermore, significant volumes of mixed NGLs are contractually committed to our NGL fractionation facilities.

 

Although competition for NGL fractionation services is primarily based on the fractionation fee, the ability of an NGL fractionator to obtain mixed NGLs and distribute NGL products is also an important competitive factor. This ability is a function of the existence of storage infrastructure and supply and market connectivity necessary to conduct such operations. We believe that the location, scope and capability of our logistics assets, including our transportation and distribution systems, give us access to both substantial sources of mixed NGLs and a large number of end-use markets.

 

Our fractionation assets include ownership interests in three stand-alone fractionation facilities that are located on the Gulf Coast, two of which we operate, one at Mont Belvieu, Texas and the other at Lake Charles, Louisiana. We have an equity investment in the third fractionator, Gulf Coast Fractionators LP (“GCF”), also located at Mont Belvieu. We were subject to a consent decree with the Federal Trade Commission, issued December 12, 1996, that, among other things, prevented us from participating in commercial decisions regarding rates paid by third parties for fractionation services at GCF. This restriction on our activity at GCF terminated on December 12, 2016. In addition to the three stand-alone facilities in the Logistics Assets segment, see the description of fractionation assets in the North Texas System and LOU in our Gathering and Processing segment.

 

In June 2016, we commissioned an additional fractionator, Train 5, at CBF, in Mont Belvieu, Texas. This expansion added 100 MBbl/d of fractionation capacity at CBF, and is fully integrated with our existing Gulf Coast NGL storage, terminaling and delivery infrastructure, which includes an extensive network of connections to key petrochemical and industrial customers as well as our LPG export terminal at Galena Park on the Houston Ship Channel. The gross cost of Train 5 was approximately $331 million (our net cost was approximately $299 million).

 

We also have a natural gasoline hydrotreater at Mont Belvieu, Texas that removes sulfur from natural gasoline, allowing customers to meet new, more stringent environmental standards. The facility has a capacity of 40 MBbl/d and is supported by long-term fee-based contracts that have certain guaranteed volume commitments or provisions for deficiency payments.

 

The following table details the Logistics and Marketing segment’s fractionation and treating facilities:

 

 

 

 

 

 

Gross Capacity

 

Gross Throughput

 

Facility

% Owned

 

 

(MBbl/d) (1)

 

2016 (MBbl/d)

 

Operated Facilities:

 

 

 

 

 

 

 

 

 

 

Lake Charles Fractionator (Lake Charles, LA) (2)

 

100.0

 

 

 

55.0

 

 

0.8

 

Cedar Bayou Fractionator (Mont Belvieu, TX) (3)

 

88.0

 

 

 

493.0

 

 

316.6

 

Targa LSNG Hydrotreater (Mont Belvieu, TX)

 

100.0

 

 

 

35.0

 

 

 

 

LSNG treating volumes

 

 

 

 

 

 

 

 

24.9

 

Benzene treating volumes

 

 

 

 

 

 

 

 

22.1

 

Non-operated Facilities:

 

 

 

 

 

 

 

 

 

 

Gulf Coast Fractionator (Mont Belvieu, TX)

 

38.8

 

 

 

125.0

 

 

99.5

 

       ________________

 

(1)

Actual fractionation capacities may vary due to the Y-grade composition of the gas being processed and does not contemplate ethane rejection.

 

(2)

Lake Charles fractionator was idled during 2016 as raw volumes were directed to Cedar Bayou fractionator. Lake Charles fractionator will run in a mode of ethane/propane splitting for a local petrochemical customer starting in 2017 but will still be configured to handle raw product.

 

(3)

Gross capacity represents 100% of the volume. Capacity includes 40 MBbl/d of additional butane/gasoline fractionation capacity.

 

NGL Storage and Terminaling

 

In general, our NGL storage assets provide warehousing of mixed NGLs, NGL products and petrochemical products in underground wells, which allows for the injection and withdrawal of such products at various times in order to meet supply and demand cycles. Similarly, our terminaling operations provide the inbound/outbound logistics and warehousing of mixed NGLs, NGL products and petrochemical products in above-ground storage tanks. Our NGL underground storage and terminaling facilities serve single markets, such as propane, as well as multiple products and markets. For example, the Mont Belvieu and Galena Park facilities have extensive

18


pipeline connections for mixed NGL supply and delivery of component NGLs. In addition, some of our facilities are connected to marine, rail and truck loading and unloading facilities that provide services and products to our customers. We provide long and short-term storage and terminaling services and throughput capability to third-party customers for a fee.

 

Across the Logistics and Marketing segment, we own or operate a total of 39 storage wells at our facilities with a net storage capacity of approximately 66 MMBbl, the usage of which may be limited by brine handling capacity, which is utilized to displace NGLs from storage.

 

We operate our storage and terminaling facilities to support our key fractionation facilities at Mont Belvieu and Lake Charles for receipt of mixed NGLs and storage of fractionated NGLs to service the petrochemical, refinery, export and heating customers/markets as well as our wholesale domestic terminals that focus on logistics to service the heating market customer base. In September 2013, we commissioned Phase I of our international export expansion project that includes our facilities at both Mont Belvieu and the Galena Park Marine Terminal near Houston, Texas. Phase I of the project expanded our export capability to approximately 3.5 to 4 MMBbl per month of propane and/or butane. Included in the Phase I expansion was the capability to export international grade low ethane propane. With the completion of Phase I, we also added capabilities to load VLGC vessels alongside the small and medium sized export vessels that we can also load for export. We completed Phase II of the international export expansion project in the third quarter of 2014, which added approximately 3 MMBbl per month of export capacity. We continue to experience demand growth for US-based NGLs (both propane and butane) for export into international markets.

 

The following table details the Logistics and Marketing segment’s NGL storage facilities:

 

 

 

 

 

Number of

 

Gross Storage

 

Facility

% Owned

 

Location

Permitted Wells

 

Capacity (MMBbl)

 

Hackberry Storage (Lake Charles, LA)

100

 

Cameron Parish, LA

12

(1)

 

20.0

 

Mont Belvieu Storage

100

 

Chambers County, TX

21

(2)

 

46.8

 

       ________________

 

(1)

Five of 12 owned wells leased to Citgo Petroleum Corporation under long-term leases.

 

(2)

Excludes six non-owned wells we operate on behalf of Chevron Phillips Chemical Company LLC ("CPC"). Includes the first of four new permitted wells, which became operational in June 2015. The second new well has been drilled and is in the process of being washed.

 

The following table details the Logistics and Marketing segment’s NGL terminaling facilities:

 

 

 

 

 

 

Throughput for 2016

 

Gross Storage

 

Facility

% Owned

 

Location

Description

(Million gallons)

 

Capacity (MMBbl)

 

Galena Park Marine Terminal (1)

100

 

Harris County, TX

NGL import/export terminal

 

3,705.3

 

 

0.7

 

Mont Belvieu Terminal

100

 

Chambers County, TX

Transport and storage terminal

 

16,660.3

 

 

42.1

 

Hackberry Terminal

100

 

Cameron Parish, LA

Storage terminal

 

661.5

 

 

17.8

 

________________

 

(1)

Volumes reflect total import and export across the dock/terminal and may also include volumes that have also been handled at the Mont Belvieu Terminal.

 

Our fractionation, storage and terminaling business includes approximately 900 miles of company-owned pipelines to transport mixed NGLs and specification products.

 

Petroleum Logistics

 

Our Petroleum Logistics business owns and operates storage and terminaling facilities in Texas, Maryland and Washington. These facilities not only serve the refined petroleum products and crude oil markets, but also include LPGs and biofuels. The following table details the Logistics and Marketing segment’s petroleum logistics facilities:

 

 

 

 

 

 

 

Throughput for 2016

 

Gross Storage

 

Facility

% Owned

 

Location

Description

(Million gallons)

 

Capacity (MMBbl)

 

Channelview Terminal

100

 

Harris County, TX

Transport and storage terminal

 

179.7

 

 

0.6

 

Baltimore Terminal

100

 

Baltimore County, MD

Transport and storage terminal

 

59.6

 

 

0.5

 

Sound Terminal

100

 

Pierce County, WA

Transport and storage terminal

 

548.0

 

 

1.4

 

Patriot

100

 

Harris County, TX

Dock and land for expansion (Not in service)

N/A

 

N/A

 

 

19


NGL Distribution and Marketing

 

We market our own NGL production and also purchase component NGL products from other NGL producers and marketers for resale. Additionally, we also purchase product for resale in our Logistics and Marketing segment, including exports. During the year ended December 31, 2016, our distribution and marketing services business sold an average of approximately 477.5 MBbl/d of NGLs.

 

We generally purchase mixed NGLs at a monthly pricing index less applicable fractionation, transportation and marketing fees and resell these component products to petrochemical manufacturers, refineries and other marketing and retail companies. This is primarily a physical settlement business in which we earn margins from purchasing and selling NGL products from customers under contract. We also earn margins by purchasing and reselling NGL products in the spot and forward physical markets. To effectively serve our distribution and marketing customers, we contract for and use many of the assets included in our Logistics and Marketing segment.

 

Wholesale Domestic Marketing

 

Our wholesale domestic propane marketing operations primarily sell propane and related logistics services to major multi-state retailers, independent retailers and other end-users. Our propane supply primarily originates from both our refinery/gas supply contracts and our other owned or managed logistics and marketing assets. We sell propane at a fixed posted price or at a market index basis at the time of delivery and in some circumstances, we earn margin on a netback basis.

 

The wholesale propane marketing business is significantly impacted by seasonal and weather-driven demand, particularly in the winter, which can impact the price and volume of propane sold in the markets we serve.

 

Refinery Services

 

In our refinery services business, we typically provide NGL balancing services via contractual arrangements with refiners to purchase and/or market propane and to supply butanes. We use our commercial transportation assets (discussed below) and contract for and use the storage, transportation and distribution assets included in our Logistics and Marketing segment to assist refinery customers in managing their NGL product demand and production schedules. This includes both feedstocks consumed in refinery processes and the excess NGLs produced by other refining processes. Under typical netback purchase contracts, we generally retain a portion of the resale price of NGL sales or receive a fixed minimum fee per gallon on products sold. Under netback sales contracts, fees are earned for locating and supplying NGL feedstocks to the refineries based on a percentage of the cost to obtain such supply or a minimum fee per gallon.

 

Key factors impacting the results of our refinery services business include production volumes, prices of propane and butanes, as well as our ability to perform receipt, delivery and transportation services in order to meet refinery demand.

 

Commercial Transportation

 

Our NGL transportation and distribution infrastructure includes a wide range of assets supporting both third-party customers and the delivery requirements of our marketing and asset management business. We provide fee-based transportation services to refineries and petrochemical companies throughout the Gulf Coast area. Our assets are also deployed to serve our wholesale distribution terminals, fractionation facilities, underground storage facilities and pipeline injection terminals. These distribution assets provide a variety of ways to transport products to and from our customers.

 

Our transportation assets, as of December 31, 2016, include approximately 700 railcars that we lease and manage, approximately 90 leased and managed transport tractors and 20 company-owned pressurized NGL barges.

 

Natural Gas Marketing

 

We also market natural gas available to us from the Gathering and Processing segment, purchase and resell natural gas in selected U.S. markets and manage the scheduling and logistics for these activities.

 

The following table details the Logistics and Marketing segment’s raw NGL, propane and butane terminaling facilities:

 

20


 

 

 

 

 

Throughput

 

Usable Storage

 

 

 

 

 

 

for 2016

 

Capacity

 

Facility

% Owned

 

Location

Description

(Million gallons) (1)

 

(Million gallons)

 

Calvert City Terminal

100

 

Marshall County, KY

Propane terminal

 

9.7

 

 

0.1

 

Greenville Terminal

100

 

Washington County, MS

Marine propane terminal

 

18.7

 

 

1.5

 

Port Everglades Terminal

100

 

Broward County, FL

Marine propane terminal

 

11.7

 

 

1.6

 

Tyler Terminal

100

 

Smith County, TX

Propane terminal

 

9.0

 

 

0.2

 

Abilene Transport (2)

100

 

Taylor County, TX

Raw NGL transport terminal

 

22.7

 

 

0.1

 

Bridgeport Transport (2)

100

 

Jack County, TX

Raw NGL transport terminal

 

36.0

 

 

0.1

 

Gladewater Transport (2)

100

 

Gregg County, TX

Raw NGL transport terminal

 

10.1

 

 

0.3

 

Chattanooga Terminal

100

 

Hamilton County, TN

Propane terminal

 

11.8

 

 

0.9

 

Sparta Terminal

100

 

Sparta County, NJ

Propane terminal

 

12.4

 

 

0.2

 

Hattiesburg Terminal (3)

50

 

Forrest County, MS

Propane terminal

 

422.3

 

 

179.8

 

Winona Terminal

100

 

Flagstaff County, AZ

Propane terminal

 

15.0

 

 

0.3

 

Sound Terminal

100

 

Pierce County, WA

Propane terminal

 

6.8

 

 

0.2

 

Jacksonville Transload  (4)

100

 

Duval County, FL

Butane transload

 

1.8

 

 

-

 

Fort Lauderdale Transload  (4)

100

 

Broward County, FL

Butane transload

 

0.4

 

 

-

 

Eagle Lake Transload  (4)

100

 

Polk County, FL

Butane/propane transload

 

6.4

 

 

-

 

________________

 

(1)

Throughputs include volumes related to exchange agreements and third party storage agreements.

 

(2)

Volumes reflect total transport and injection volumes.

 

(3)

Throughput volume reflects 100% of the facility capacity. In 2016, usable storage capacity decreased from 302.0 million gallons to 179.8 million gallons due to the decommissioning of two storage wells.

 

(4)

Rail-to-truck transload equipment.

 

Operational Risks and Insurance

 

We are subject to all risks inherent in the midstream natural gas, crude oil and petroleum logistics businesses. These risks include, but are not limited to, explosions, fires, mechanical failure, terrorist attacks, product spillage, weather, nature and inadequate maintenance of rights-of-way and could result in damage to or destruction of operating assets and other property, or could result in personal injury, loss of life or environmental pollution, as well as curtailment or suspension of operations at the affected facility. Targa maintains, on behalf of us and our subsidiaries, general public liability, property, boiler and machinery and business interruption insurance in amounts that we consider to be appropriate for such risks. Such insurance is subject to deductibles that we consider reasonable and not excessive given the current insurance market environment.

 

The occurrence of a significant loss that is not fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. While we currently maintain levels and types of insurance that we believe to be prudent under current insurance industry market conditions, our inability to secure these levels and types of insurance in the future could negatively impact our business operations and financial stability, particularly if an uninsured loss were to occur. No assurance can be given that we will be able to maintain these levels of insurance in the future at rates considered commercially reasonable, particularly named windstorm coverage and contingent business interruption coverage for our onshore operations.

 

Competition

 

We face strong competition in acquiring new natural gas or crude oil supplies. Competition for natural gas and crude oil supplies is primarily based on the location of gathering and processing facilities, pricing arrangements, reputation, efficiency, flexibility, reliability and access to end-use markets or liquid marketing hubs. Competitors to our gathering and processing operations include other natural gas gatherers and processors, such as major interstate and intrastate pipeline companies, master limited partnerships and oil and gas producers. Our major competitors for natural gas supplies in our current operating regions include Kinder Morgan, WTG Gas Processing, L.P. (“WTG”), DCP, Devon Energy Corporation (“Devon”), Enbridge Inc., Enlink Midstream Partners LP, Energy Transfer Partners, L.P., ONEOK, Gulf South Pipeline Company, LP, Hanlon Gas Processing, Ltd., J-W Operating Company, Louisiana Intrastate Gas Company L.L.C., Enable Midstream Partners LP and several other interstate pipeline companies. Our competitors for crude oil gathering services in North Dakota include Crestwood Equity Partners LP, Kinder Morgan, Tesoro Corporation, Caliber Midstream Partners, L.P., Bridger Pipeline LLC, Paradigm Energy Partners, LLC and Summit Midstream Partners, LLC. Our competitors may have greater financial resources than we possess.

 

We also compete for NGL products to market through our Logistics and Marketing segment. Our competitors include major oil and gas producers who market NGL products for their own account and for others. Additionally, we compete with several other NGL marketing companies, including EPD, DCP, ONEOK and BP p.l.c.

 

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Additionally, we face competition for mixed NGLs supplies at our fractionation facilities. Our competitors include large oil, natural gas and petrochemical companies. The fractionators in which we own an interest in the Mont Belvieu region compete for volumes of mixed NGLs with other fractionators also located at Mont Belvieu, Texas. Among the primary competitors are EPD, ONEOK and LoneStar NGL LLC. In addition, certain producers fractionate mixed NGLs for their own account in captive facilities. The Mont Belvieu fractionators also compete on a more limited basis with fractionators in Conway, Kansas and a number of decentralized, smaller fractionation facilities in Texas, Louisiana and New Mexico. Our other fractionation facilities compete for mixed NGLs with the fractionators at Mont Belvieu as well as other fractionation facilities located in Louisiana. Our customers who are significant producers of mixed NGLs and NGL products or consumers of NGL products may develop their own fractionation facilities in lieu of using our services. Our primary competitors in providing export services to our customers are EPD, Phillips 66 and LoneStar NGL LLC.

 

Regulation of Operations

 

Regulation of pipeline gathering and transportation services, natural gas sales and transportation of NGLs may affect certain aspects of our business and the market for our products and services.

 

Regulation of Interstate Natural Gas Pipelines

 

VGS is regulated by FERC under the Natural Gas Act of 1938 (“NGA”), and the Natural Gas Policy Act of 1978 (“NGPA”). VGS operates under a FERC-approved, open-access tariff that establishes the rates and the terms and conditions under which the system provides services to its customers. Pursuant to FERC’s jurisdiction, existing pipeline rates and/or terms and conditions of service may be challenged by customer complaint or by FERC and proposed rate changes or changes in the terms and conditions of service may be challenged by protest. Generally, FERC’s authority extends to: transportation of natural gas; rates and charges for natural gas transportation; certification and construction of new facilities; extension or abandonment of services and facilities; maintenance of accounts and records; commercial relationships and communications between pipelines and certain affiliates; terms and conditions of service and service contracts with customers; depreciation and amortization policies; and acquisition and disposition of facilities.

 

VGS holds a certificate of public convenience and necessity issued by FERC permitting the construction, ownership, and operation of its interstate natural gas pipeline facilities and the provision of transportation services. This certificate authorization requires VGS to provide on a nondiscriminatory basis open-access services to all customers who qualify under its FERC gas tariff. FERC has the power to prescribe the accounting treatment of items for regulatory purposes. Thus, the books and records of VGS may be periodically audited by FERC.

 

The maximum recourse rates that may be charged by VGS for its services are established through FERC’s ratemaking process. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of service, including recovery of and a return on the pipeline’s investment. Key determinants in the ratemaking process are costs of providing service, allowed rate of return and volume throughput and contractual capacity commitment assumptions. VGS is permitted to discount its firm and interruptible rates without further FERC authorization down to the variable cost of performing service, provided they do not “unduly discriminate.” The applicable recourse rates and terms and conditions for service are set forth in each pipeline’s FERC-approved tariff. Rate design and the allocation of costs also can impact a pipeline’s profitability. VGS currently has revised tariff sheets on file with FERC, seeking to increase the rates for service on VGS. Several of VGS’s customers protested the proposed increase, and the ratemaking proceeding remains pending. A hearing before a FERC administrative law judge on the proposed increase is scheduled to begin on April 18, 2017.

 

We also own (in conjunction with Pioneer) and operate the Driver Residue Pipeline, a gas transmission pipeline extending from our Driver processing plant in West Texas just over ten miles to points of interconnection with intrastate and interstate natural gas transmission pipelines. We have obtained a limited jurisdiction certificate of public convenience and necessity under the Natural Gas Act for the Driver Residue Pipeline. In the certificate order, among other things, FERC waived requirements pertaining to the filing of an initial rate for service, the filing of a tariff and compliance with specified accounting and reporting requirements. As such, the Driver Residue Pipeline is not currently subject to conventional rate regulation; to requirements FERC imposes on “open access” interstate natural gas pipelines; to the obligation to file and maintain a tariff; or to the obligation to conform to certain business practices and to file certain reports. If, however, we receive a bona fide request for firm service on the Driver Residue Pipeline from a third party, FERC would reexamine the waivers it has granted us and would require us to file for authorization to offer “open access” transportation under its regulations, which would impose additional costs upon us.

 

Gathering Pipeline Regulation

 

Our natural gas gathering operations are typically subject to ratable take and common purchaser statutes in the states in which we operate. The common purchaser statutes generally require gathering pipelines to purchase or take without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another or one source of supply over another. The regulations under these statutes can have the effect of imposing some restrictions on our ability as

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an owner of gathering facilities to decide with whom it contracts to gather natural gas. The states in which we operate have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. The rates we charge for gathering are deemed just and reasonable unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties.

 

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation as a natural gas company by FERC under the NGA. We believe that the natural gas pipelines in our gathering systems, including the gas gathering systems that are part of the Badlands and of the Pelican and Seahawk gathering systems, meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, to the extent our gathering systems buy and sell natural gas, such gatherers, in their capacity as buyers and sellers of natural gas, are now subject to Order No. 704. See “—Other Federal Laws and Regulations Affecting Our Industry—FERC Market Transparency Rules.”  

 

Intrastate Pipeline Regulation

 

Though our natural gas intrastate pipelines are not subject to regulation by FERC as natural gas companies under the NGA, our intrastate pipelines may be subject to certain FERC-imposed reporting requirements depending on the volume of natural gas purchased or sold in a given year. See “—Other Federal Laws and Regulations Affecting Our Industry—FERC Market Transparency Rules.”

 

Our intrastate pipelines located in Texas are regulated by the Railroad Commission of Texas (the “RRC”). Our Texas intrastate pipeline, Targa Intrastate Pipeline LLC (“Targa Intrastate”), owns the intrastate pipeline that transports natural gas from its Shackelford processing plant to an interconnect with Atmos Pipeline-Texas that in turn delivers gas to the West Texas Utilities Company’s Paint Creek Power Station. Targa Intrastate also owns a 1.65-mile, ten-inch diameter intrastate pipeline that transports natural gas from a third-party gathering system into the Chico system in Denton County, Texas. Targa Intrastate is a gas utility subject to regulation by the RRC and has a tariff on file with such agency. Our other Texas intrastate pipeline, Targa Gas Pipeline LLC, owns a multi-county intrastate pipeline that transports gas in Crane, Ector, Midland, and Upton Counties, Texas, as well as some lines in North Texas. Targa Gas Pipeline LLC is a gas utility subject to regulation by the RRC.

Our Louisiana intrastate pipeline, Targa Louisiana Intrastate LLC owns an approximately 60-mile intrastate pipeline system that receives all of the natural gas it transports within or at the boundary of the State of Louisiana. Because all such gas ultimately is consumed within Louisiana, and since the pipeline’s rates and terms of service are subject to regulation by the Office of Conservation of the Louisiana Department of Natural Resources (“DNR”), the pipeline qualifies as a Hinshaw pipeline under Section 1(c) of the NGA and thus is exempt from most FERC regulation.

 

We have an ownership interest of 50% of the capacity in a 50-mile long intrastate natural gas transmission pipeline, which extends from the tailgate of three natural gas processing plants located near Pettus, Texas to interconnections with existing intrastate and interstate natural gas pipelines near Refugio, Texas. The capacity is held by our subsidiary, TPL SouthTex Transmission Company LP (“TPL SouthTex Transmission”), which is entitled to transport natural gas through its capacity on behalf of third parties to both intrastate and interstate markets. Because the jointly owned pipeline system was initially interconnected only with intrastate markets, each of the capacity holders qualified as an “intrastate pipeline” within the meaning of the NGPA and therefore is able to provide transportation of natural gas to interstate markets under Section 311 of the NGPA. Under Sections 311 and 601 of the NGPA, an intrastate pipeline may transport natural gas in interstate commerce without becoming subject to FERC regulation as a “natural-gas company” under the Natural Gas Act. Transportation of natural gas under authority of Section 311 must be filed with FERC and must be shown to be “fair and equitable.” TPL SouthTex Transmission has a Statement of Operating Conditions on file with FERC, and FERC has accepted the rates, which TPL SouthTex Transmission’s predecessor filed, as being in accordance with the “fair and equitable” standard. TPL SouthTex Transmission is required to file, on or before November 6, 2017, a petition for approval of its then-existing rates, or to propose a new rate, applicable to NGPA Section 311 service.

 

We also operate natural gas pipelines that extend from the tailgate of our processing plants to interconnections with both intrastate and interstate natural gas pipelines. Although these “plant tailgate” pipelines may operate at transmission pressure levels and may transport “pipeline quality” natural gas, we believe they are exempt from FERC’s jurisdiction under the Natural Gas Act under FERC’s “stub” line exemption.

 

Texas, Louisiana, Oklahoma, and Kansas have adopted complaint-based regulation of intrastate natural gas transportation activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to pipeline access and rate discrimination. The rates we charge for intrastate transportation are deemed just and reasonable unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties.

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Our intrastate NGL pipelines in Louisiana gather mixed NGLs streams that we own from processing plants in Louisiana and deliver such streams to the Gillis fractionators in Lake Charles, Louisiana, where the mixed NGLs streams are fractionated into various products. We deliver such refined petroleum products (ethane, propane, butanes and natural gasoline) out of our fractionator to and from Targa-owned storage, to other third-party facilities and to various third-party pipelines in Louisiana. These pipelines are not subject to FERC regulation or rate regulation by the DNR, but are regulated by United States Department of Transportation (“DOT”) safety regulations.

 

Our intrastate pipelines in North Dakota are subject to the various regulations of the State of North Dakota. In addition, various federal agencies within the U.S. Department of the Interior, particularly the federal Bureau of Land Management (“BLM”), Office of Natural Resources Revenue (formerly the Minerals Management Service) and the Bureau of Indian Affairs, as well as the Three Affiliated Tribes, promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation. Please see “-Other State and Local Regulation of Operations” below.

 

Natural Gas Processing

 

Our natural gas gathering and processing operations are not presently subject to FERC regulation.  However, since May 2009 we have been required to report to FERC information regarding natural gas sale and purchase transactions for some of our operations depending on the volume of natural gas transacted during the prior calendar year. See “—Other Federal Laws and Regulations Affecting Our Industry—FERC Market Transparency Rules.” There can be no assurance that our processing operations will continue to be exempt from other FERC regulation in the future.

 

Sales of Natural Gas and NGLs

 

The price at which we buy and sell natural gas and NGLs is currently not subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical purchases and sales of these energy commodities and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodities Futures Trading Commission (“CFTC”). See “—Other Federal Laws and Regulations Affecting Our Industry—EP Act of 2005.” Since May 2009, we have been required to report to FERC information regarding natural gas sale and purchase transactions for some of our operations depending on the volume of natural gas transacted during the prior calendar year. See “—Other Federal Laws and Regulations Affecting Our Industry—FERC Market Transparency Rules.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.

 

Other State and Local Regulation of Operations

 

Our business activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies pursuant thereto, governing a wide variety of matters, including marketing, production, pricing, community right-to-know, protection of the environment, safety and other matters. In addition, the Three Affiliated Tribes promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation, on which we operate a significant portion of our Badlands gathering and processing assets. The Three Affiliated Tribes is a sovereign nation having the right to enforce certain laws and regulations independent from federal, state and local statutes and regulations. For additional information regarding the potential impact of federal, state, tribal or local regulatory measures on our business, see “Risk Factors—Risks Related to Our Business.”

 

Interstate Common Carrier Liquids Pipeline Regulation

 

Targa NGL Pipeline Company LLC (“Targa NGL”) has interstate NGL pipelines that are considered common carrier pipelines subject to regulation by FERC under the Interstate Commerce Act (the “ICA”). More specifically, Targa NGL owns a regulated twelve-inch diameter pipeline that runs between Lake Charles, Louisiana, and Mont Belvieu, Texas. This pipeline can move mixed NGLs and purity NGL products. Targa NGL also owns an eight-inch diameter pipeline and a twenty-inch diameter pipeline, each of which run between Mont Belvieu, Texas, and Galena Park, Texas. The eight-inch and the twenty-inch pipelines are also regulated and are part of an extensive mixed NGL and purity NGL pipeline receipt and delivery system that provides services to domestic and foreign import and export customers. The ICA requires that we maintain tariffs on file with FERC for each of these pipelines. Those tariffs set forth the rates we charge for providing transportation services as well as the rules and regulations governing these services. The ICA requires, among other things, that rates on interstate common carrier pipelines be “just and reasonable” and non-discriminatory. All shippers on these pipelines are our subsidiaries.

 

Targa NGL also owns a twelve-inch diameter pipeline that runs between Mont Belvieu, Texas, and Galena Park, Texas, that transports NGLs and that has qualified for a waiver of applicable FERC regulatory requirements under the ICA based on current circumstances. The crude oil pipeline system that is part of the Badlands assets also qualifies for such a waiver. Such waivers are subject to

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revocation, however, should the pipeline’s circumstances change. FERC could, either at the request of other entities or on its own initiative, assert that some or all of the transportation on these pipelines is within its jurisdiction. In the event that FERC were to determine that one or both of these pipelines no longer qualified for waiver, we would likely be required to file a tariff with FERC for one or both of these pipelines, as applicable, provide a cost justification for the transportation charge, and provide service to all potential shippers without undue discrimination. Such a change in the jurisdictional status of transportation on these pipelines could adversely affect our results of operations.

 

Other Federal Laws and Regulations Affecting Our Industry

 

EP Act of 2005

 

The EP Act of 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act of 2005 provides FERC with the power to assess civil penalties of up to $1 million per day for violations of the NGA and $1 million per violation per day for violations of the NGPA. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce, including VGS. In 2006, FERC issued Order No. 670 to implement the anti-market manipulation provision of the EP Act of 2005. Order No. 670 does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of 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, which includes the annual reporting requirements under a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (Order No. 704), and the quarterly reporting requirement under Order No. 735. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

 

FERC Market Transparency Rules

 

Beginning in 2007, FERC has issued a number of rules intended to provide for greater marketing transparency in the natural gas industry, including Order Nos. 704, 720, and 735. Under Order No. 704, wholesale buyers and sellers of more than 2.2 Bcf of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices.

 

Under Order No. 720, certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtu of gas over the previous three calendar years, are required to post on a daily basis certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000 MMBtu/d and interstate pipelines are required to post information regarding the provision of no-notice service. In October 2011, Order No. 720 as clarified was vacated by the Court of Appeals for the Fifth Circuit. We take the position that, at this time, all of our entities are exempt from Order No. 720 as currently effective.

 

Under Order No. 735, intrastate pipelines providing transportation services under Section 311 of the NGPA and Hinshaw pipelines operating under Section 1(c) of the NGA are required to report on a quarterly basis more detailed transportation and storage transaction information, including: rates charged by the pipeline under each contract; receipt and delivery points and zones or segments covered by each contract; the quantity of natural gas the shipper is entitled to transport, store, or deliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and the shipper. Order No. 735 also extends FERC’s periodic review of the rates charged by the subject pipelines from three years to five years. On rehearing, FERC reaffirmed Order No. 735 with some modifications.  As currently written, this rule does not apply to our Hinshaw pipelines.

 

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such FERC action materially differently than other midstream natural gas companies with whom we compete.


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Environmental, Operational Health and Safety and Pipeline Safety Matters

General

Our operations are subject to numerous federal, tribal, state and local laws and regulations governing the discharge of materials into the environment, worker health and safety, or otherwise relating to environmental protection. As with the industry generally, compliance with current and anticipated environmental laws and regulations increases our overall cost of business, including our costs to construct, maintain, upgrade and decommission equipment and facilities. We have implemented programs and policies designed to monitor and pursue operation of our pipelines, plants and other facilities in a manner consistent with existing environmental laws and regulations. The trend in environmental regulation is to place more restrictions and limitations on activities that may adversely affect the environment and thus, any changes in environmental laws and regulations or reinterpretation of enforcement policies that result in more stringent and costly waste management or disposal, pollution control or remediation requirements could have a material adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. See Risk Factor “Failure to comply with environmental laws or regulations or an accidental release into the environment may cause us to incur significant costs and liabilities” under Item 1A of this Form 10-K for further discussion on environmental compliance matters. See “Item 3. Legal Proceedings – Environmental Proceedings” for a discussion of certain recent or pending proceedings related to environmental matters.

Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not become material in the future. The following is a summary of the more significant existing environmental, worker health and safety and pipeline safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous Substances and Waste

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and comparable state laws impose joint and several, strict liability on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Liability of these “responsible persons” under CERCLA may include the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the U.S. Environmental Protection Agency (“EPA”) and, in some instances, third-parties to act in response to threats to the public health or the environment and to seek to recover from these responsible persons the costs they incur. It is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. We generate materials in the course of our operations that are regulated as “hazardous substances” under CERCLA or similar state statutes and, as a result, may be jointly and severally liable under CERCLA or similar state statutes for all or part of the costs required to clean up releases of hazardous substance into the environment.  

We also generate solid wastes, including hazardous wastes that are subject to the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes additional stringent requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of our operations, we generate petroleum product wastes and ordinary industrial wastes such as paint wastes, waste solvents and waste compressor oils that are regulated as hazardous wastes. Although certain materials generated in the exploration, development or production of crude oil and natural gas are excluded from RCRA’s hazardous waste regulations, there have been efforts from time to time to remove this exclusion. For example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Any future changes in law or regulation that result in these wastes, including wastes currently generated during our or our customers’ operations, being designated as “hazardous wastes” and therefore subject to more rigorous and costly disposal requirements, could have a material adverse effect on our capital expenditures and operating expenses and, with respect to such adverse effects on our customers, could reduce the need for our services.

We currently own or lease, and have in the past owned or leased, properties that for many years have been used for midstream natural gas and NGL activities and refined petroleum product and crude oil storage and terminaling activities. Hydrocarbons or other substances and wastes may have been released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons or other substances and wastes have been taken for treatment or disposal. In addition, certain of these

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properties have been operated by third parties whose treatment and release of hydrocarbons or other substances and wastes was not under our control. These properties and any hydrocarbons, substances and wastes released 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 released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) and to perform remedial operations to prevent future contamination, the costs of which activities could have a material adverse effect on our business and results of operations.

Air Emissions

The federal Clean Air Act (“CAA”) and comparable state laws and regulations restrict the emission of air pollutants from many sources, including processing plants and compressor stations and also impose various monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. The need to obtain permits has the potential to delay the development of oil and natural gas related projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone to 70 parts per billion under both the primary and secondary standards to provide requisite protection of the public health and welfare. The EPA is expected to make final geographical attainment designations and issue final non-attainment area requirements pursuant to this NAAQS rule by late 2017. Any designations or requirements that result in reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are expected to implement more stringent regulations, which could apply to our operations. Additionally, in June 2016, the EPA (1) published a final rule updating federal permitting regulations for stationary sources in the oil and natural gas industry by defining and clarifying the meaning of the term “adjacent” for determining when separate surface sites and the equipment at those sites will be aggregated for permitting purposes; (2) finalized new source performance standards for emissions of methane and volatile organic compounds from new and modified oil and natural gas production facilities and natural gas gathering, processing, and transmission facilities; and (3) finalized a Federal Implementation Plan to implement a minor new source review permitting program for oil and gas stationary sources on certain Indian reservations, including the Fort Berthold Indian Reservation in North Dakota.  Compliance with these or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business.

Climate Change

The EPA has determined that greenhouse gas (“GHG”) emissions endanger public health and the environment because emissions of such gases are contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted regulations under the CAA related to GHG emissions. See Risk Factor “The adoption and implementation of climate change legislation and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the products and services we provide” under Item 1A of this Form 10-K for further discussion on climate change and regulation of GHG emissions.

Water Discharges

The Federal Water Pollution Control Act (“Clean Water Act” or “CWA”) and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters. Pursuant to the CWA and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the United States. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by the EPA or the analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities and such permits may require us to monitor and sample the storm water runoff. The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. The CWA and analogous state laws also may impose substantial civil and criminal penalties for non-compliance including spills and other non-authorized discharges.  

In May 2015, the EPA released a final rule attempting to clarify the federal jurisdictional reach over waters of the United States, but legal challenges to this rule followed and the rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015 while that appellate court considers lawsuits opposing implementation of the rule.  In February 2016, a split three-judge panel of the Sixth Circuit held that the Sixth Circuit had jurisdiction over the petition for review of this final rule.  Following the Sixth Circuit’s February 2016 jurisdictional decision, several federal district courts dismissed challenges to the rule on jurisdictional grounds.  However, the federal district court for the District of North Dakota, which issued an order in August 2015 finding jurisdiction and enjoining the rule, placed its case on hold in May 2016, pending the outcome of the cases before the Sixth Circuit. In January 2017,

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the U.S. Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts. Any expansion to CWA jurisdiction in areas where we or our customers operate could impose additional permitting obligations on us or our customers.

The Federal Oil Pollution Act of 1990 (“OPA”) which amends the CWA, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” under the OPA includes owners and operators of onshore facilities, such as our plants and our pipelines. Under the OPA, owners and operators of facilities that handle, store, or transport oil are required to develop and implement oil spill response plans, and establish and maintain evidence of financial responsibility sufficient to cover liabilities related to an oil spill for which such parties could be statutorily responsible.

Hydraulic Fracturing

Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. The process is typically regulated by state oil and gas commissions, but several federal agencies, including the EPA and the BLM have asserted regulatory authority over aspects of the process. Also, Congress has considered, and some states and local governments have adopted legal requirements that could impose more stringent permitting, disclosure or well construction requirements on hydraulic fracturing activities. While we do not conduct hydraulic fracturing, if new or more stringent federal, state, or local legal restrictions or prohibitions relating to the hydraulic fracturing process are adopted in areas where our oil and natural gas exploration and production customers operate, those customers could incur potentially significant added costs to comply with such requirements and experience delays or curtailment in the pursuit of exploration, development or production activities, which could reduce demand for our gathering, processing and fractionation services. See Risk Factor “Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact our revenues by decreasing the volumes of natural gas, NGLs or crude oil through our facilities and reducing the utilization of our assets” under Item 1A of this Form 10-K for further discussion on hydraulic fracturing.

Endangered Species Act Considerations

The federal Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Some of our facilities may be located in areas that are designated as habitat for endangered or threatened species. If endangered species are located in areas of the underlying properties where we plan to conduct development activities, such work could be prohibited or delayed or expensive mitigation may be required. Similar protections are offered to migrating birds under the federal Migratory Bird Treaty Act. Moreover, as a result of one or more settlements approved by the federal government, the U.S. Fish and Wildlife Service (“FWS”) must make determinations within specified timeframes on the listing of numerous species as endangered or threatened under the ESA. The designation of previously unprotected species as threatened or endangered in areas where we or our customers operate could cause us or our customers to incur increased costs arising from species protection measures and could result in delays or limitations in our customers’ performance of operations, which could reduce demand for our services.

Employee Health and Safety

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. The regulations apply to any process that (1) involves a listed chemical in a quantity at or above the threshold quantity specified in the regulation for that chemical, or (2) involves certain flammable gases or flammable liquids present on site in one location in a quantity of 10,000 pounds or more. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt. We have implemented an internal program of inspection designed to monitor and pursue operations in a manner consistent with worker safety requirements.

Pipeline Safety

Many of our natural gas, NGL and crude pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the DOT (or state analogs) under the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) with respect to natural gas, and the Hazardous Liquids Pipeline Safety Act of 1979 (“HLPSA”) with respect to crude oil, NGLs and condensates. The NGPSA and HLPSA govern the design, installation, testing, construction, operation, replacement and management of natural gas, crude oil, NGL and condensate pipeline facilities. Pursuant to these acts, PHMSA has promulgated regulations governing, among

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other things, pipeline wall thicknesses, design pressures, maximum operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures. Additionally, PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquids pipelines that, in the event of a pipeline leak or rupture, could affect “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areas. Our past compliance with the NGPSA and HLPSA has not had a material adverse effect on our results of operations; however, future compliance with these pipeline safety laws could result in increased costs.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”), which became law in January 2012, increases the penalties for safety violations, establishes additional safety requirements for newly constructed pipelines and requires studies of safety issues that could result in the adoption of new regulatory requirements for existing pipelines. More recently, in June 2016, President Obama signed the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”) that extends PHMSA’s statutory mandate through 2019 and, among other things, requires PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and develop new safety standards for natural gas storage facilities by June 22, 2018. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016 to implement the agency's expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment.

We, or the entities in which we own an interest, inspect our pipelines regularly in a manner consistent with state and federal maintenance requirements. Nonetheless, the adoption of new or amended regulations by PHMSA that result in more stringent or costly pipeline integrity management or safety standards could have a significant adverse effect on us. For example, in April 2015, PHMSA proposed rulemaking that would require leak detection for all hazardous liquid pipelines and require periodic assessment of hazardous liquid pipelines not already covered by the integrity management requirements. In a second example, in March 2016, PHMSA announced a proposed rulemaking that would impose new or more stringent requirements for certain gas lines and gathering lines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for gas pipelines in newly defined “moderate consequence areas” that contain as few as 5 dwellings within a potential impact area; requiring gas pipelines installed before 1970, which were previously excluded from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures (“MAOP”); and requiring certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, MAOP limits, line markers and emergency planning standards.  Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements and also require consideration of seismicity in evaluating threats to pipelines. Such legislative and regulatory changes could have a material effect on our operations and costs of transportation services. In the absence of the PHMSA promulgating any legal requirements, state agencies, to the extent authorized, may promulgate state standards, including standards for rural gathering lines. For example, in 2013, the Texas Legislature authorized the RRC to adopt and implement safety standards applicable to the intrastate transportation of hazardous liquids and natural gas in rural locations by gathering pipeline.

In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. Texas, Louisiana and New Mexico, for example, have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastate pipelines transporting natural gas and NGLs. North Dakota has similarly implemented regulatory programs applicable to intrastate natural gas pipelines. We currently estimate an annual average cost of $3.6 million for the years 2017 through 2019 to perform necessary integrity management program testing on our pipelines required by existing PHMSA and state regulations. This estimate does not include the costs, if any, of any repair, remediation, or preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which costs could be substantial. However, we do not expect that any such costs would be material to our financial condition or results of operations.

See Risk Factor “Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation” under Item 1A of this Form 10-K for further discussion on pipeline safety standards.

Title to Properties and Rights-of-Way

 

Our real property falls into two categories: (1) parcels that we own in fee and (2) 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 plants and other major 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 plant sites and major facilities are located is held by us pursuant to ground leases between us, as lessee, and the fee owner of the lands, as lessors. We and our predecessors have leased these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit, lease or license, and we believe that we have satisfactory

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title to all of our material leases, easements, rights-of-way, permits, leases and licenses.

 

Employees

 

We do not have any employees. To carry out our operations, Targa employs approximately 1,970 people who support primarily our operations. None of those employees are covered by collective bargaining agreements. Targa considers its employee relations to be good.

 

Financial Information by Reportable Segment

 

See “Segment Information” included under Note 23 of the “Consolidated Financial Statements” for a presentation of financial results by reportable segment and see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations–Results of Operations–By Reportable Segment” for a discussion of our financial results by segment.

 

Available Information

 

We make certain filings with the Securities and Exchange Commission (“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, http://www.targaresources.com, as soon as reasonably practicable after they are filed with the SEC. The filings are also available through the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. Also, these filings are available on the internet at http://www.sec.gov. Our press releases and recent analyst presentations are also available on our website.

 

Item 1A. Risk Factors.

Limited partner interests are inherently different from 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. The nature of our business activities subjects us to certain hazards and risks. You should consider carefully the following risk factors together with all the other information contained in this report. If any of the following risks were actually to occur, then our business, financial condition, cash flows and results of operations could be materially adversely affected.

 

We have a substantial amount of indebtedness which may adversely affect our financial position.

 

We have a substantial amount of indebtedness. As of December 31, 2016, we had $4,002.2 million outstanding under our senior unsecured notes and $54.6 million of outstanding senior notes of TPL, excluding $0.5 million of unamortized net discounts and premiums. We also had $275.0 million outstanding under our accounts receivable securitization facility (the “Securitization Facility”). In addition, we had $150.0 million of borrowings outstanding, $13.2 million of letters of credit outstanding and $1,436.8 million of additional borrowing capacity available under the TRP Revolver. Our $1.6 billion TRP Revolver allows us to request increases in commitments up to an additional $500 million. For the years ended December 31, 2016, 2015 and 2014, our consolidated interest expense, net was $233.5 million, $207.8 million and $143.8 million.  

 

This substantial level of indebtedness increases the possibility that we may be unable to generate cash sufficient to pay, when due, the principal of, interest on or other amounts due in respect of indebtedness. This substantial indebtedness, combined with lease and other financial obligations and contractual commitments, could have other 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;

 

 

satisfying our obligations with respect to indebtedness may be more difficult and any failure to comply with the obligations of any debt instruments could result in an event of default under the agreements governing such indebtedness;

 

 

we will need a portion of cash flow to make interest payments on debt, reducing the funds that would otherwise be available for operations and future business opportunities;