ý | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Delaware | 44-0382470 |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
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/d | per day | |
ARO | Asset retirement obligation | |
Bcf | Billion cubic feet | |
Btu | British thermal units | |
Citrus | Citrus, LLC | |
CrossCountry | CrossCountry Energy, LLC | |
EPA | United States Environmental Protection Agency | |
ETC | La Grange Acquisition, L.P., a wholly-owned subsidiary of ETP, which conducts business under the assumed named of Energy Transfer Company | |
ETE | Energy Transfer Equity, L.P. | |
ETP | Energy Transfer Partners, L.P., a subsidiary of ETE | |
ETP Holdco | ETP Holdco Corporation, the entity formed by ETP and ETE in 2012 to own the equity interests in Southern Union and Sunoco, Inc. | |
Exchange Act | Securities Exchange Act of 1934 | |
FERC | Federal Energy Regulatory Commission | |
GAAP | Accounting principles generally accepted in the United States of America | |
Lake Charles LNG | Lake Charles LNG Company, LLC | |
LIBOR | London Interbank Offered Rate | |
LNG | Liquefied natural gas | |
LNG Holdings | Trunkline LNG Holdings, LLC | |
MGE | Missouri Gas Energy | |
NEG | New England Gas Company | |
NGL | Natural gas liquids | |
OPEB plans | Other postretirement employee benefit plans | |
Panhandle | PEPL and its subsidiaries | |
PCBs | Polychlorinated biphenyls | |
PEPL | Panhandle Eastern Pipe Line Company, LP | |
PEPL Holdings | PEPL Holdings, LLC | |
PRPs | Potentially responsible parties | |
Regency | Regency Energy Partners LP, a subsidiary of ETE | |
Sea Robin | Sea Robin Pipeline Company, LLC | |
SEC | United States Securities and Exchange Commission | |
Southern Union | Southern Union Company | |
Southwest Gas | Pan Gas Storage, LLC (d.b.a. Southwest Gas) | |
SUGS | Southern Union Gas Services | |
TBtu | Trillion British thermal units | |
Trunkline | Trunkline Gas Company, LLC | |
• | 2.2 million ETP common units; |
• | 31.4 million Regency common units and 6.3 million Regency Class F Units; |
• | Approximately $176 million of Southern Union third party long-term debt and $1.09 billion of notes payable to ETP; and |
• | Guarantee of $600 million of Regency senior notes. |
Year Ended December 31, | |||||
2014 | 2013 | ||||
PEPL transportation | 625 | 613 | |||
Trunkline transportation | 694 | 722 | |||
Sea Robin transportation | 130 | 141 |
Approximate Miles of Pipelines | |||
PEPL | 6,000 | ||
Trunkline | 3,000 | ||
Sea Robin | 1,000 | ||
Peak Day Delivery Capacity (Bcf/d) | |||
PEPL | 2.8 | ||
Trunkline | 1.7 | ||
Sea Robin | 2.3 | ||
Underground Storage Capacity-Owned (Bcf) | 68.1 | ||
Underground Storage Capacity-Leased (Bcf) | 33.3 | ||
Approximate Number of Transportation Customers | 500 | ||
Weighted Average Remaining Life in Years of Firm Transportation Contracts (1) | |||
PEPL | 3.8 | ||
Trunkline | 7.8 | ||
Sea Robin (2) | N/A | ||
Weighted Average Remaining Life in Years of Firm Storage Contracts (1) | |||
PEPL | 7.1 | ||
Trunkline | 4.0 |
(1) | Weighted by firm capacity volumes. |
(2) | Sea Robin’s contracts are primarily interruptible, with only four firm contracts in place. |
• | Borrowing costs associated with existing debt obligations could increase in the event of a credit rating downgrade; |
• | The costs of refinancing debt that is maturing or any new debt issuances could increase due to a credit rating downgrade; and |
• | FERC may be unwilling to allow the Company to pass along increased debt service costs to natural gas customers. |
• | examine and potentially acquire regulated or unregulated businesses, including transportation and storage assets and gathering and processing businesses within the natural gas industry; |
• | enter into joint venture agreements and/or other transactions with other industry participants or financial investors; |
• | selectively divest parts of its business, including parts of its core operations; and |
• | continue expanding its existing operations. |
• | its success in valuing and bidding for the opportunities; |
• | its ability to assess the risks of the opportunities; |
• | its ability to obtain regulatory approvals on favorable terms; and |
• | its access to financing on acceptable terms. |
• | the risk of diverting management’s attention from day-to-day operations; |
• | the risk that the acquired businesses will require substantial capital and financial investments; |
• | the risk that the investments will fail to perform in accordance with expectations; and |
• | the risk of substantial difficulties in the transition and integration process. |
• | the Company’s ability to obtain necessary approvals and permits from FERC and other regulatory agencies on a timely basis and on terms that are acceptable to it; |
• | the ability to access sufficient capital at reasonable rates to fund expansion projects, especially in periods of prolonged economic decline when the Company may be unable to access capital markets; |
• | the availability of skilled labor, equipment, and materials to complete expansion projects; |
• | adverse weather conditions; |
• | potential changes in federal, state and local statutes, regulations, and orders, including environmental requirements that delay or prevent a project from proceeding or increase the anticipated cost of the project; |
• | impediments on the Company’s ability to acquire rights-of-way or land rights or to commence and complete construction on a timely basis or on terms that are acceptable to it; |
• | the Company’s ability to construct projects within anticipated costs, including the risk that the Company may incur cost overruns, resulting from inflation or increased costs of equipment, materials, labor, contractor productivity, delays in construction or other factors beyond its control, that the Company may not be able to recover from its customers; |
• | the lack of future growth in natural gas supply and/or demand; and |
• | the lack of transportation, storage and throughput commitments. |
• | terms and conditions of service; |
• | the types of services interstate pipelines may or must offer their customers; |
• | construction of new facilities; |
• | acquisition, extension or abandonment of services or facilities; |
• | reporting and information posting requirements; |
• | accounts and records; and |
• | relationships with affiliated companies involved in all aspects of the natural gas and energy businesses. |
• | perform ongoing assessments of pipeline integrity; |
• | identify and characterize applicable threats to pipeline segments that could impact a high consequence area; |
• | improve data collection, integration and analysis; |
• | repair and remediate the pipeline as necessary; and |
• | implement preventive and mitigating actions. |
• | changes in demand for natural gas and related services by customers, in the composition of the Company’s customer base and in the sources of natural gas accessible to the Company’s system; |
• | the effects of inflation and the timing and extent of changes in the prices and overall demand for and availability of natural gas as well as electricity, oil, coal and other bulk materials and chemicals; |
• | adverse weather conditions, such as warmer or colder than normal weather in the Company’s service territories, as applicable, and the operational impact of natural disasters; |
• | changes in laws or regulations, third-party relations and approvals, and decisions of courts, regulators and/or governmental bodies affecting or involving the Company, including deregulation initiatives and the impact of rate and tariff proceedings before FERC and various state regulatory commissions; |
• | the speed and degree to which additional competition, including competition from alternative forms of energy, is introduced to the Company’s business and the resulting effect on revenues; |
• | the impact and outcome of pending and future litigation and/or regulatory investigations, proceedings or inquiries; |
• | the ability to comply with or to successfully challenge existing and/or or new environmental, safety and other laws and regulations; |
• | unanticipated environmental liabilities; |
• | the uncertainty of estimates, including accruals and costs of environmental remediation; |
• | the impact of potential impairment charges; |
• | the ability to acquire new businesses and assets and to integrate those operations into its existing operations, as well as its ability to expand its existing businesses and facilities; |
• | the timely receipt of required approvals by applicable governmental entities for the construction and operation of the pipelines and other projects; |
• | the ability to complete expansion projects on time and on budget; |
• | the ability to control costs successfully and achieve operating efficiencies, including the purchase and implementation of new technologies for achieving such efficiencies; |
• | the impact of factors affecting operations such as maintenance or repairs, environmental incidents, natural gas pipeline system constraints and relations with labor unions representing bargaining-unit employees; |
• | the performance of contractual obligations by customers, service providers and contractors; |
• | exposure to customer concentrations with a significant portion of revenues realized from a relatively small number of customers and any credit risks associated with the financial position of those customers; |
• | changes in the ratings of the Company’s debt securities; |
• | the risk of a prolonged slow-down in growth or decline in the United States economy or the risk of delay in growth or decline in the United States economy, including liquidity risks in United States credit markets; |
• | the impact of unsold pipeline capacity being greater than expected; |
• | changes in interest rates and other general market and economic conditions, and in the Company’s ability to obtain additional financing on acceptable terms, whether in the capital markets or otherwise; |
• | declines in the market prices of equity and debt securities and resulting funding requirements for other postretirement benefit plans; |
• | acts of nature, sabotage, terrorism or other similar acts that cause damage to the facilities or those of the Company’s suppliers’ or customers’ facilities; |
• | market risks beyond the Company’s control affecting its risk management activities including market liquidity, commodity price volatility and counterparty creditworthiness; |
• | the availability/cost of insurance coverage and the ability to collect under existing insurance policies; |
• | the risk that material weaknesses or significant deficiencies in internal controls over financial reporting could emerge or that minor problems could become significant; |
• | changes in accounting rules, regulations and pronouncements that impact the measurement of the results of operations, the timing of when such measurements are to be made and recorded and the disclosures surrounding these activities; |
• | the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, environmental compliance, climate change initiatives, authorized rates of recovery of costs (including pipeline relocation costs), and permitting for new natural gas production accessible to the Company’s systems; |
• | market risks affecting the Company’s pricing of its services provided and renewal of significant customer contracts; |
• | actions taken to protect species under the Endangered Species Act and the effect of those actions on the Company’s operations; |
• | the impact of union disputes, employee strikes or work stoppages and other labor-related disruptions; and |
• | other risks and unforeseen events, including other financial, operational and legal risks and uncertainties detailed from time to time in filings with the SEC. |
Year Ended December 31, | |||||||
2014 | 2013 | ||||||
OPERATING REVENUES: | |||||||
Transportation and storage of natural gas | $ | 555 | $ | 576 | |||
LNG terminalling | — | 216 | |||||
Other | 26 | 293 | |||||
Total operating revenues (1) | 581 | 1,085 | |||||
OPERATING EXPENSES: | |||||||
Cost of natural gas and other energy | 3 | 228 | |||||
Operating, maintenance and general | 255 | 361 | |||||
Depreciation and amortization | 130 | 189 | |||||
Goodwill impairment | — | 689 | |||||
Total operating expenses | 388 | 1,467 | |||||
OPERATING INCOME (LOSS) | 193 | (382 | ) | ||||
OTHER INCOME (EXPENSE): | |||||||
Interest expense, net of interest capitalized | (66 | ) | (111 | ) | |||
Equity in earnings (losses) of unconsolidated affiliates | (12 | ) | 15 | ||||
Interest income — affiliates | 23 | 9 | |||||
Other, net | 5 | (3 | ) | ||||
Total other expenses, net | (50 | ) | (90 | ) | |||
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 143 | (472 | ) | ||||
Income tax expense from continuing operations | 146 | 98 | |||||
LOSS FROM CONTINUING OPERATIONS | (3 | ) | (570 | ) | |||
Income from discontinued operations | — | 35 | |||||
NET LOSS | (3 | ) | (535 | ) | |||
LESS: NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST | 6 | (36 | ) | ||||
NET LOSS ATTRIBUTABLE TO PARTNERS | $ | (9 | ) | $ | (499 | ) | |
Panhandle natural gas volumes transported (TBtu): (2) | |||||||
PEPL | 625 | 613 | |||||
Trunkline | 694 | 722 | |||||
Sea Robin | 130 | 141 |
(1) | Reservation revenues comprised 83% and 88% of total operating revenues for the years ended December 31, 2014 and 2013, respectively. |
(2) | Includes transportation deliveries made throughout the Company’s pipeline network. |
• | Operating Revenues. Operating revenues decreased for the year ended December 31, 2014 compared to the prior year primarily due to the deconsolidation of Lake Charles LNG in 2014 and SUGS in 2013. In addition, the decrease in operating revenues reflected the recognition in 2013 of $52 million received in connection with the buyout of a customer contract. These decreases were partially offset by an increase of approximately $29 million due to capacity sold at higher rates and loan related activity from higher basis differentials and spot prices on the Panhandle pipeline, primarily driven by favorable impacts from the cold winter season during the first quarter of 2014. |
• | Operating Expenses. Operating expenses decreased for the year ended December 31, 2014 compared to the prior year primarily due to the deconsolidation of SUGS and Lake Charles LNG. Operating expenses included in the year ended December 31, 2013 related to SUGS and Lake Charles LNG were $56 million and $30 million, respectively. In addition, during the year ended December 31, 2013 the Company recorded a $689 million goodwill impairment related to Lake Charles LNG. The remainder of the decrease in operating, maintenance and general was primarily attributable to reduced general and administrative costs related to professional fees of $19 million. |
• | Interest Expense, Net of Interest Capitalized. Interest expense decreased for the year ended December 31, 2014 compared to the prior year due to repayment of long-term debt during 2013. |
• | Equity in Earnings (Losses) of Unconsolidated Affiliates. Equity in earnings (losses) of unconsolidated affiliates decreased primarily due to a goodwill impairment recorded by Regency. As a result, the Company recognized a non-cash loss based on its proportionate ownership in Regency. |
• | Interest Income - Affiliates. Interest income from affiliates increased for the year ended December 31, 2014 compared to the prior year due to a note receivable from ETP that was entered into during the third quarter 2013. |
• | Income Taxes. The increase in the effective tax rate for the year ended December 31, 2014 was primarily due to the Lake Charles LNG Transaction, which was treated as a sale for tax purposes, resulting in $70 million of incremental income tax expense. For the year ended December 31, 2013, the effective tax rate also reflected a $241 million tax impact as a result of a $689 million non-deductible goodwill impairment. |
• | Income From Discontinued Operations. Income from discontinued operations for the year ended December 31, 2013 reflected the results of operations of MGE and NEG, both of which were sold in 2013. |
Contractual Obligations | |||||||||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 and thereafter | |||||||||||||||||||||
Operating leases (1) | $ | 16 | $ | 2 | $ | 2 | $ | 3 | $ | 3 | $ | 2 | $ | 4 | |||||||||||||
Total long-term debt (2) (3) | 1,091 | — | — | 300 | 400 | 150 | 241 | ||||||||||||||||||||
Interest payments on debt (4) | 463 | 75 | 75 | 75 | 42 | 22 | 174 | ||||||||||||||||||||
Natural gas purchases (5) | 72 | 4 | 4 | 4 | 4 | 4 | 52 | ||||||||||||||||||||
Firm capacity payments (6) | 89 | 26 | 22 | 21 | 16 | 4 | — | ||||||||||||||||||||
OPEB funding (7) | 48 | 8 | 8 | 8 | 8 | 8 | 8 | ||||||||||||||||||||
Total (8) | $ | 1,779 | $ | 115 | $ | 111 | $ | 411 | $ | 473 | $ | 190 | $ | 479 |
(1) | Lease of various assets utilized for operations. |
(2) | The Company is party to debt agreements containing certain covenants that, if not satisfied, would give rise to an event of default that would cause such debt to become immediately due and payable. Such covenants require the Company to maintain a fixed charge coverage ratio, a leverage ratio and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. At December 31, 2014, the Company was in compliance with all of its covenants. See Note 7 to our consolidated financial statements. |
(3) | The long-term debt cash obligations exclude $99 million of unamortized fair value adjustments as of December 31, 2014. |
(4) | Interest payments on debt are based upon the applicable stated or variable interest rates as of December 31, 2014. |
(5) | The Company has tariffs in effect for its utility service areas that provide for recovery of its purchased natural gas costs under defined methodologies. |
(6) | Charges for third party storage capacity. |
(7) | Panhandle is committed to the funding levels of $8 million per year until modified by future rate proceedings, the timing of which is uncertain. |
(8) | Excludes non-current deferred tax liability of $1.51 billion due to uncertainty of the timing of future cash flows for such liabilities. |
Years Ended December 31, | |||||||
2014 | 2013 | ||||||
Audit fees (1) | $ | 800,000 | $ | 1,314,250 | |||
Audit related fees (2) | 27,500 | 547,300 | |||||
Total Fees | $ | 827,500 | $ | 1,861,550 |
(1) | Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and services related to the audit of our internal controls over financial reporting. |
(2) | Includes fees in 2013 for financial statement audits of subsidiary entities in connection with the contribution of SUGS from Southern Union to Regency and the sale of Southern Union’s distribution operations. Includes fees in 2014 and 2013 in connection with the services organization control report on PEPL’s centralized data center. |
• | the auditors’ internal quality-control procedures; |
• | any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors; |
• | the independence of the external auditors; |
• | the aggregate fees billed by our external auditors for each of the previous two years; and |
• | the rotation of the lead partner. |
(a) | The following documents are filed as a part of this Report: |
(1) | Financial Statements - see Index to Financial Statements appearing on page F-1. |
(2) | Financial Statement Schedules - None. |
(3) | Exhibits - see Index to Exhibits set forth on page E-1. |
PANHANDLE EASTERN PIPE LINE COMPANY, LP | |
Date: February 26, 2015 | By: /s/ Martin Salinas, Jr. Martin Salinas, Jr. Chief Financial Officer (duly authorized to sign on behalf of the registrant) |
Signature | Title | Date | |||
(i) | Principal executive officer: /s/ Kelcy L. Warren Kelcy L. Warren | Chief Executive Officer | February 26, 2015 | ||
(ii) | Principal financial officer: /s/ Martin Salinas, Jr. Martin Salinas, Jr. | Chief Financial Officer | February 26, 2015 | ||
(iii) | The Board of Directors of SUG Holding Company, Sole Member of Southern Union Panhandle, LLC, General Partner of Panhandle Eastern Pipe Line Company, L.P | ||||
Signature | Title | Date | |||
/s/ Kelcy L. Warren Kelcy L. Warren | Chief Executive Officer and Director, SUG Holding Company | February 26, 2015 | |||
/s/ John W. McReynolds John W. McReynolds | Director, SUG Holding Company | February 26, 2015 | |||
Exhibit Number | Description | |||
(*) | 3(a) | Certificate of Formation of Panhandle Eastern Pipe Line Company, LP. (Filed as Exhibit 3.A to Panhandle’s Form 10-K for the year ended December 31, 2004.) | ||
(*) | 3(b) | Limited Partnership Agreement of Panhandle Eastern Pipe Line Company, LP, dated as of June 29, 2004, between Southern Union Company and Southern Union Panhandle LLC. (Filed as Exhibit 3.B to Panhandle’s Form 10-K for the year ended December 31, 2004.) | ||
(*) | 3(c) | Amendment No. 1, dated January 10, 2014 to Agreement of Limited Partnership of Panhandle Eastern Pipe Line Company, LP (Filed as Exhibit 3.1 to Panhandle’s Form 8-K filed on January 10, 2014.) | ||
(*) | 4(a) | Indenture dated as of March 29, 1999, among CMS Panhandle Holding Company, Panhandle Eastern Pipe Line Company and NBD Bank (the predecessor to Bank One Trust Company, National Association, J.P. Morgan Trust Company, National Association, The Bank of New York Trust Company, N.A. and The Bank of New York Mellon Trust Company, N.A.), as Trustee. (Filed as Exhibit 4(a) to Panhandle’s Form 10-Q for the quarter ended March 31, 1999.) | ||
(*) | 4(b) | First Supplemental Indenture dated as of March 29, 1999, among CMS Panhandle Holding Company, Panhandle Eastern Pipe Line Company and NBD Bank (the predecessor to Bank One Trust Company, National Association, J.P. Morgan Trust Company, National Association, The Bank of New York Trust Company, N.A. and The Bank of New York Mellon Trust Company, N.A.), as Trustee, including a form of Guarantee by Panhandle Eastern Pipe Line Company of the obligations of CMS Panhandle Holding Company. (Filed as Exhibit 4(b) to Panhandle’s Form 10-Q for the quarter ended March 31, 1999.) | ||
(*) | 4(c) | Second Supplemental Indenture dated as of March 27, 2000, between Panhandle and Bank One Trust Company, National Association (succeeded to by The Bank of New York Mellon Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A.), as Trustee. (Filed as Exhibit 4(e) to Panhandle’s Form S-4 (File No. 333-39850) filed on June 22, 2000.) | ||
(*) | 4(d) | Third Supplemental Indenture dated as of August 18, 2003, between Panhandle and Bank One Trust Company, National Association (succeeded to by The Bank of New York Mellon Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A.), as Trustee. (Filed as Exhibit 4(d) to Panhandle’s Form 10-Q for the quarter ended September 30, 2003.) | ||
(*) | 4(e) | Fourth Supplemental Indenture dated as of March 12, 2004, between Panhandle and J.P. Morgan Trust Company, National Association (succeeded to by The Bank of New York Mellon Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A.), as Trustee. (Filed as Exhibit 4.E to Panhandle’s Form 10-K for the year ended December 31, 2004.) | ||
(*) | 4(f) | Fifth Supplemental Indenture dated as of October 26, 2007, between Panhandle and The Bank of New York Trust Company, N.A. (now known as The Bank of New York Mellon Trust Company, N.A.), as Trustee (Filed as Exhibit 4.1 to Panhandle’s Form 8-K filed on October 29, 2007.) | ||
(*) | 4(g) | Form of Sixth Supplemental Indenture, dated as of June 12, 2008, between Panhandle and The Bank of New York Trust Company, N.A. (now known as The Bank of New York Mellon Trust Company, N.A.), as Trustee (Filed as Exhibit 4.1 to Panhandle’s Form 8-K filed on June 11, 2008.) | ||
(*) | 10(a) | Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipeline Company, LP and Trunkline LNG Company, LLC, as guarantors, the financial institutions listed therein and the Bank of Tokyo-Mitsubishi UFJ, Ltd., as administrative agent, dated as of February 23, 2012 (Filed as Exhibit 10(a) to Panhandle’s Form 10-K for the year ended December 31, 2011.) | ||
(*) | 10(b) | Form of Seventh Supplemental Indenture, to be dated as of June 2, 2009, between Panhandle and The Bank of New York Mellon Trust Company, N.A. (Filed as Exhibit 4.1 to Panhandle’s Form 8-K filed on May 28, 2009.) | ||
(*) | 10(c) | Amended and Restated Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipe Line Company, LP and CrossCountry Citrus, LLC, as guarantors, the financial institutions listed therein and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of June 29, 2007 (Filed as Exhibit 10.1 to Panhandle’s Form 8-K filed on July 6, 2007.) | ||
(*) | 10(d) | Amendment Number 1 to the Amended and Restated Credit Agreement between Trunkline LNG Holdings, LLC as borrower, Panhandle Eastern Pipe Line Company, LP and CrossCountry Citrus, LLC, as guarantors, the financial institutions listed therein and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of June 13, 2008 (Filed as Exhibit 10(b) to Panhandle’s Form 10-Q for the quarter ended June 30, 2008.) | ||
Exhibit Number | Description | |||
(*) | 10(e) | Amended and Restated Promissory Note made by CrossCountry Citrus, LLC, as borrower, in favor of Trunkline LNG Holdings LLC, as holder, dated as of June 13, 2008 (Filed as Exhibit 10(d) to Panhandle’s Form 10-Q for the quarter ended June 30, 2008.) | ||
(*) | 10(f) | Transfer Agreement, dated February 19, 2014, by and between Energy Transfer Partners, L.P. and Panhandle Eastern Pipe Line Company, LP (Filed as Exhibit 10.1 to Panhandle’s Form 8-K filed on February 19, 2014.) | ||
12.1 | Computation of Ratio of Earnings to Fixed Charges. | |||
31.1 | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |||
31.2 | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |||
(**) | 32.1 | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
(**) | 32.2 | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
99.1 | Audited financial statements of Regency Energy Partners LP as of and for the years ended December 31, 2014, 2013 and 2012. | |||
(*) | 99.2 | Audited financial statements of Midcontinent Express Pipeline LLC as of and for the years ended December 31, 2014, 2013 and 2012 (incorporated by reference to Exhibit 99.3 of Regency Energy Partners LP Form 10-K for the year ended December 31, 2014, File No. 1-35262.) | ||
101.INS | XBRL Instance Document | |||
101.SCH | XBRL Taxonomy Extension Schema Document | |||
101.CAL | XBRL Taxonomy Calculation Linkbase Document | |||
101.DEF | XBRL Taxonomy Extension Definitions Document | |||
101.LAB | XBRL Taxonomy Label Linkbase Document | |||
101.PRE | XBRL Taxonomy Presentation Linkbase Document | |||
* | Indicates exhibit incorporated by reference as indicated; all other exhibits are filed herewith, except as noted otherwise. |
** | Furnished herewith. |
Financial Statements and Supplementary Data: | Page: |
December 31, | |||||||
2014 | 2013 | ||||||
ASSETS | |||||||
CURRENT ASSETS: | |||||||
Cash and cash equivalents | $ | 32 | $ | 17 | |||
Accounts receivable, net | 58 | 69 | |||||
Accounts receivable from related companies | 128 | 64 | |||||
Exchanges receivable | 11 | 19 | |||||
Inventories | 119 | 203 | |||||
Other current assets | 13 | 18 | |||||
Total current assets | 361 | 390 | |||||
PROPERTY, PLANT AND EQUIPMENT: | |||||||
Plant in service | 3,352 | 4,208 | |||||
Construction work in progress | 43 | 70 | |||||
3,395 | 4,278 | ||||||
Accumulated depreciation and amortization | (269 | ) | (216 | ) | |||
Net property, plant and equipment | 3,126 | 4,062 | |||||
INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 1,443 | 1,525 | |||||
GOODWILL | 1,152 | 1,336 | |||||
NOTE RECEIVABLE FROM RELATED PARTY | — | 396 | |||||
OTHER NON-CURRENT ASSETS, net | 109 | 147 | |||||
Total assets | $ | 6,191 | $ | 7,856 |
December 31, | |||||||
2014 | 2013 | ||||||
LIABILITIES AND PARTNERS’ CAPITAL | |||||||
CURRENT LIABILITIES: | |||||||
Current maturities of long-term debt | $ | 1 | $ | 1 | |||
Accounts payable | 6 | 33 | |||||
Accounts payable to related companies | 38 | 181 | |||||
Exchanges payable | 114 | 207 | |||||
Accrued interest | 12 | 12 | |||||
Price risk management liabilities | — | 10 | |||||
Customer advances and deposits | 10 | 17 | |||||
Accrued and other current liabilities | 56 | 52 | |||||
Total current liabilities | 237 | 513 | |||||
LONG-TERM DEBT, less current maturities | 1,189 | 1,246 | |||||
NOTE PAYABLE TO RELATED PARTY | — | 1,090 | |||||
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES | — | 15 | |||||
DEFERRED INCOME TAXES | 1,511 | 1,659 | |||||
ADVANCES FROM AFFILIATES | 51 | — | |||||
OTHER NON-CURRENT LIABILITIES | 278 | 265 | |||||
COMMITMENTS AND CONTINGENCIES (Note 14) | |||||||
PARTNERS’ CAPITAL: | |||||||
Partners’ capital | 2,925 | 3,551 | |||||
Accumulated other comprehensive income | — | 3 | |||||
Total partners’ capital | 2,925 | 3,554 | |||||
Noncontrolling interest | — | (486 | ) | ||||
Total liabilities and partners’ capital | $ | 6,191 | $ | 7,856 |
Successor | Predecessor | |||||||||||||||
Year Ended December 31, 2014 | Year Ended December 31, 2013 | Period from Acquisition (March 26, 2012) to December 31, 2012 | Period from January 1, 2012 to March 25, 2012 | |||||||||||||
OPERATING REVENUES: | ||||||||||||||||
Transportation and storage of natural gas | $ | 555 | $ | 576 | $ | 437 | $ | 121 | ||||||||
LNG terminalling | — | 216 | 166 | 51 | ||||||||||||
Other | 26 | 293 | 660 | 271 | ||||||||||||
Total operating revenues | 581 | 1,085 | 1,263 | 443 | ||||||||||||
OPERATING EXPENSES: | ||||||||||||||||
Cost of natural gas and other energy | 3 | 228 | 521 | 197 | ||||||||||||
Operating, maintenance and general | 255 | 361 | 377 | 116 | ||||||||||||
Depreciation and amortization | 130 | 189 | 179 | 49 | ||||||||||||
Goodwill impairment | — | 689 | — | — | ||||||||||||
Total operating expenses | 388 | 1,467 | 1,077 | 362 | ||||||||||||
OPERATING INCOME (LOSS) | 193 | (382 | ) | 186 | 81 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||||
Interest expense, net of interest capitalized | (66 | ) | (111 | ) | (131 | ) | (50 | ) | ||||||||
Equity in earnings (losses) of unconsolidated investments | (12 | ) | 15 | (7 | ) | 16 | ||||||||||
Interest income — affiliates | 23 | 9 | — | — | ||||||||||||
Other, net | 5 | (3 | ) | 2 | (2 | ) | ||||||||||
Total other expenses, net | (50 | ) | (90 | ) | (136 | ) | (36 | ) | ||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 143 | (472 | ) | 50 | 45 | |||||||||||
Income tax expense from continuing operations | 146 | 98 | 39 | 12 | ||||||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS | (3 | ) | (570 | ) | 11 | 33 | ||||||||||
Income from discontinued operations | — | 35 | 28 | 17 | ||||||||||||
NET INCOME (LOSS) | (3 | ) | (535 | ) | 39 | 50 | ||||||||||
LESS: NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST | 6 | (36 | ) | (49 | ) | 10 | ||||||||||
NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS | $ | (9 | ) | $ | (499 | ) | $ | 88 | $ | 40 |
Successor | Predecessor | |||||||||||||||
Year Ended December 31, 2014 | Year Ended December 31, 2013 | Period from Acquisition (March 26, 2012) to December 31, 2012 | Period from January 1, 2012 to March 25, 2012 | |||||||||||||
Net income (loss) | $ | (3 | ) | $ | (535 | ) | $ | 39 | $ | 50 | ||||||
Other comprehensive income (loss), net of tax: | ||||||||||||||||
Change in fair value of interest rate hedges | — | — | — | 4 | ||||||||||||
Reclassification of unrealized loss on interest rate hedges into earnings | — | — | — | 5 | ||||||||||||
Change in fair value of commodity hedges | — | (3 | ) | (4 | ) | 3 | ||||||||||
Reclassification of unrealized (gain) loss on commodity hedges into earnings | — | 6 | 1 | (1 | ) | |||||||||||
Actuarial gain (loss) relating to postretirement benefits | (3 | ) | 25 | (22 | ) | — | ||||||||||
Reclassification of prior service credit relating to other postretirement benefits into earnings | — | — | — | 1 | ||||||||||||
(3 | ) | 28 | (25 | ) | 12 | |||||||||||
Comprehensive income (loss) | $ | (6 | ) | $ | (507 | ) | $ | 14 | $ | 62 |
Partners’ Capital | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interest | Total | ||||||||||||
Predecessor | |||||||||||||||
Balance, December 31, 2011 | $ | 1,809 | $ | (16 | ) | $ | 847 | $ | 2,640 | ||||||
Equity-based compensation | — | — | 2 | 2 | |||||||||||
Restricted stock issuances | — | — | (3 | ) | (3 | ) | |||||||||
Purchase of treasury stock | — | — | (1,450 | ) | (1,450 | ) | |||||||||
Net income | 40 | — | 10 | 50 | |||||||||||
Other comprehensive income, net of tax | — | 3 | 9 | 12 | |||||||||||
Balance, March 25, 2012 | $ | 1,849 | $ | (13 | ) | $ | (585 | ) | $ | 1,251 | |||||
Successor | |||||||||||||||
Balance, March 26, 2012 | $ | 3,962 | $ | — | $ | (49 | ) | $ | 3,913 | ||||||
Dividends paid to Southern Union stockholders | — | — | (65 | ) | (65 | ) | |||||||||
Capital contributions | — | — | 166 | 166 | |||||||||||
Net income (loss) | 88 | — | (49 | ) | 39 | ||||||||||
Other comprehensive loss, net of tax | — | (9 | ) | (16 | ) | (25 | ) | ||||||||
Balance, December 31, 2012 | 4,050 | (9 | ) | (13 | ) | 4,028 | |||||||||
Dividends paid to Southern Union stockholders | — | — | (313 | ) | (313 | ) | |||||||||
Sales of MGE and NEG, net of tax | — | — | 12 | 12 | |||||||||||
SUGS Contribution | — | — | (135 | ) | (135 | ) | |||||||||
Net loss | (499 | ) | — | (36 | ) | (535 | ) | ||||||||
Other comprehensive income (loss), net of tax | — | 12 | (1 | ) | 11 | ||||||||||
Balance, December 31, 2013 | 3,551 | 3 | (486 | ) | 3,068 | ||||||||||
Equity-based compensation | 1 | — | — | 1 | |||||||||||
Distribution to partners | (102 | ) | — | — | (102 | ) | |||||||||
Lake Charles LNG Transaction | (20 | ) | — | (23 | ) | (43 | ) | ||||||||
Panhandle Merger | (502 | ) | (1 | ) | 503 | — | |||||||||
Net income (loss) | (9 | ) | — | 6 | (3 | ) | |||||||||
Other | 6 | — | — | 6 | |||||||||||
Other comprehensive loss, net of tax | — | (2 | ) | — | (2 | ) | |||||||||
Balance, December 31, 2014 | $ | 2,925 | $ | — | $ | — | $ | 2,925 |
Successor | Predecessor | |||||||||||||||
Year Ended December 31, 2014 | Year Ended December 31, 2013 | Period from Acquisition (March 26, 2012) to December 31, 2012 | Period from January 1, 2012 to March 25, 2012 | |||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||||||||||
Net income (loss) | $ | (3 | ) | $ | (535 | ) | $ | 39 | $ | 50 | ||||||
Reconciliation of net income to net cash provided by operating activities: | ||||||||||||||||
Depreciation and amortization (including discontinued operations) | 130 | 189 | 206 | 57 | ||||||||||||
Goodwill impairment | — | 689 | — | — | ||||||||||||
Deferred income taxes | (139 | ) | 181 | 90 | 23 | |||||||||||
Provision for bad debts | — | 7 | 3 | 1 | ||||||||||||
Amortization included in interest expense | (22 | ) | (30 | ) | (25 | ) | 1 | |||||||||
Unrealized (gain) loss on derivatives | (25 | ) | (52 | ) | 12 | — | ||||||||||
Non-cash compensation expense | 5 | 6 | — | 2 | ||||||||||||
Equity in (earnings) losses of unconsolidated affiliates | 12 | (15 | ) | 7 | (16 | ) | ||||||||||
Distributions from unconsolidated affiliates | 6 | 15 | 1 | — | ||||||||||||
Net gain on curtailment of OPEB plans | — | — | (15 | ) | — | |||||||||||
Other non-cash | 1 | 20 | 12 | — | ||||||||||||
Changes in operating assets and liabilities, net of merger impacts | 192 | (159 | ) | (178 | ) | 79 | ||||||||||
Net cash flows provided by operating activities | 157 | 316 | 152 | 197 | ||||||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||||||
Proceeds from SUGS Contribution | — | 482 | — | — | ||||||||||||
Proceeds from sale of MGE assets, net of transaction costs | — | 1,008 | — | — | ||||||||||||
Proceeds from Citrus Merger | — | — | — | 1,895 | ||||||||||||
Proceeds from affiliates | 20 | — | — | 37 | ||||||||||||
Capital expenditures | (109 | ) | (250 | ) | (238 | ) | (60 | ) | ||||||||
Distributions from unconsolidated affiliates in excess of cumulative earnings | 65 | 39 | 6 | — | ||||||||||||
Other | (16 | ) | 5 | (1 | ) | (2 | ) | |||||||||
Net cash flows (used in) provided by investing activities | (40 | ) | 1,284 | (233 | ) | 1,870 | ||||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||||||
Distributions to partners | (102 | ) | (313 | ) | (65 | ) | (19 | ) | ||||||||
Capital contribution from ETE | — | — | 166 | — | ||||||||||||
Issuance of loans from affiliates | — | 1,669 | 55 | — | ||||||||||||
Repayments of loans from affiliates | — | (975 | ) | (55 | ) | — | ||||||||||
Issuance of long-term debt | — | — | — | 455 | ||||||||||||
Repayment of long-term debt | — | (1,795 | ) | — | (1,048 | ) | ||||||||||
Net change in revolving credit facilities | — | (210 | ) | (2 | ) | 12 | ||||||||||
Purchase of treasury stock | — | — | — | (1,450 | ) | |||||||||||
Other | — | (8 | ) | (6 | ) | (4 | ) | |||||||||
Net cash flows (used in) provided by financing activities | (102 | ) | (1,632 | ) | 93 | (2,054 | ) | |||||||||
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | 15 | (32 | ) | 12 | 13 | |||||||||||
CASH AND CASH EQUIVALENTS, beginning of period | 17 | 49 | 37 | 24 | ||||||||||||
CASH AND CASH EQUIVALENTS, end of period | $ | 32 | $ | 17 | $ | 49 | $ | 37 |
1. | OPERATIONS AND ORGANIZATION: |
• | PEPL, which is wholly-owned by SUG Holding Company, an indirect wholly-owned subsidiary of ETP; |
• | Trunkline, a direct wholly-owned subsidiary of PEPL; |
• | Sea Robin, an indirect wholly-owned subsidiary of PEPL; and |
• | Southwest Gas, a direct wholly-owned subsidiary of PEPL. |
2. | ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL: |
Successor | Predecessor | |||||||||||||||
Year Ended December 31, 2014 | Year Ended December 31, 2013 | Period from Acquisition (March 26, 2012) to December 31, 2012 | Period from January 1, 2012 to March 25, 2012 | |||||||||||||
NON-CASH INVESTING ACTIVITIES: | ||||||||||||||||
Contribution from affiliate | $ | 376 | $ | — | $ | — | $ | — | ||||||||
SUPPLEMENTAL CASH FLOW INFORMATION: | ||||||||||||||||
Accrued capital expenditures | $ | 15 | $ | 13 | $ | 101 | $ | 9 | ||||||||
Cash paid for interest, net of interest capitalized | $ | 75 | $ | 142 | $ | 132 | $ | 39 |
December 31, | |||||||
2014 | 2013 | ||||||
Natural gas (1) | $ | 105 | $ | 184 | |||
Materials and supplies | 14 | 19 | |||||
$ | 119 | $ | 203 |
(1) | Natural gas volumes held for operations at December 31, 2014 and 2013 were 34.3 TBtu and 42.8 TBtu, respectively. |
Successor | Predecessor | |||||||||||
Year Ended December 31, 2014 | Year Ended December 31, 2013 | Period from Acquisition (March 26, 2012) to December 31, 2012 | Period from January 1, 2012 to March 25, 2012 | |||||||||
Phillips 66 Company(1) | — | % | 10 | % | 28 | % | 35 | % | ||||
BG Energy Holdings LTD(2) | — | 22 | 14 | 14 | ||||||||
Ameren Corporation | 11 | 6 | 3 | 4 | ||||||||
Other top 10 customers | 40 | 20 | 22 | 21 | ||||||||
Remaining customers | 49 | 42 | 33 | 26 | ||||||||
Total percentage | 100 | % | 100 | % | 100 | % | 100 | % |
(1) | SUGS, which was deconsolidated on April 30, 2013, had contracted to sell its entire owned or controlled output of NGL equity volumes to Phillips 66. Pricing for the NGL equity volumes sold to Phillips 66 throughout the contract period was OPIS pricing based at Mont Belvieu, Texas delivery points. |
(2) | BG Energy Holdings LTD is the sole customer of Lake Charles LNG, which was deconsolidated effective January 1, 2014. See Note 3. |
• | Level 1 – Observable inputs such as quoted prices in active markets for identical assets or liabilities; |
• | Level 2 – Observable inputs such as: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active and do not require significant adjustment based on unobservable inputs; or (iii) valuations based on pricing models, discounted cash flow methodologies or similar techniques where significant inputs (e.g., interest rates, yield curves, etc.) are derived principally from observable market data, or can be corroborated by observable market data, for substantially the full term of the assets or liabilities; and |
• | Level 3 – Unobservable inputs, including valuations based on pricing models, discounted cash flow methodologies or similar techniques where at least one significant model assumption or input is unobservable. Unobservable inputs are used to the extent that observable inputs are not available and reflect the Company’s own assumptions about the assumptions market participants would use in pricing the assets or liabilities. Unobservable inputs are based on the best information available in the circumstances, which might include the Company’s own data. |
3. | MERGERS, DECONSOLIDATIONS, AND RELATED TRANSACTIONS: |
Successor | Predecessor | ||||||||
Year Ended December 31, 2013 | Period from Acquisition (March 26, 2012) to December 31, 2012 | Period from January 1, 2012 to March 25, 2012 | |||||||
Revenue from discontinued operations | 415 | 324 | 190 | ||||||
Net income of discontinued operations, excluding effect of taxes and overhead allocations | 65 | 43 | 27 |
Cash and cash equivalents | $ | 37 | |
Other current assets | 519 | ||
Property and equipment | 6,242 | ||
Goodwill | 2,497 | ||
Identified intangibles (1) | 55 | ||
Other non-current assets | 290 | ||
Long-term debt, including current portion | (3,334 | ) | |
Deferred income taxes | (1,419 | ) | |
Other liabilities | (974 | ) | |
Total fair value of partners’ capital | $ | 3,913 |
(1) | Identified intangibles will be amortized over a life of approximately 17.5 years and are included in Other non-current assets in the consolidated balance sheets. |
4. | RELATED PARTY TRANSACTIONS: |
December 31, | |||||||
2014 | 2013 | ||||||
Non-current notes receivable from related party — ETP | $ | — | $ | 396 | |||
Accounts receivable from related companies (1) | $ | 128 | $ | 64 | |||
Accounts payable to related companies (2) | $ | 38 | $ | 181 | |||
Non-current note payable to related party — ETP | $ | — | $ | 1,090 | |||
Advances from affiliates | $ | 51 | $ | — |
(1) | Accounts receivable from related companies reflected above primarily related to services provided for ETE, ETP and other affiliates. |
(2) | Accounts payable to related companies reflected above primarily related to payroll funding and various services provided by ETP and other affiliates. |
Successor | Predecessor | |||||||||||||||
Year Ended December 31, 2014 | Year Ended December 31, 2013 | Period from Acquisition (March 26, 2012) to December 31, 2012 | Period from January 1, 2012 to March 25, 2012 | |||||||||||||
Operating revenues (1) | $ | 33 | $ | 56 | $ | 29 | $ | 4 | ||||||||
Cost of natural gas and other energy | — | 17 | 21 | — | ||||||||||||
Operating, maintenance and general | 49 | 71 | 125 | (2) | 14 | |||||||||||
Interest expense, net of interest capitalized | — | 31 | 3 | — | ||||||||||||
Interest income — affiliates | 23 | 9 | — | — | ||||||||||||
Equity in earnings (losses) of unconsolidated investments | (12 | ) | 15 | (7 | ) | 16 |
(1) | Represents transportation and storage revenues with ETC and Sunoco, Inc., subsidiaries of ETP, in the successor periods. |
(2) | Primarily represents corporate charges for employee expenses related to the ETE Merger offset by expenses attributable to services provided by Panhandle on behalf of other affiliate companies. |
Successor | Predecessor | |||||||||||||||
Year Ended December 31, 2014 | Year Ended December 31, 2013 | Period from Acquisition (March 26, 2012) to December 31, 2012 | Period from January 1, 2012 to March 25, 2012 | |||||||||||||
Distributions related to investment in: | ||||||||||||||||
ETP | $ | 9 | $ | 8 | $ | 6 | $ | — | ||||||||
Regency | 61 | 44 | — | — |
5. | INVESTMENTS IN UNCONSOLIDATED AFFILIATES: |
Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
Revenue | $ | 4,951 | $ | 2,521 | $ | 2,000 | |||||
Operating income (loss) | (17 | ) | 55 | 30 | |||||||
Net income (loss) | (142 | ) | 27 | 34 |
6. | COMPREHENSIVE INCOME: |
Successor | Predecessor | |||||||||||||||
Year Ended December 31, 2014 | Year Ended December 31, 2013 | Period from Acquisition (March 26, 2012) to December 31, 2012 | Period from January 1, 2012 to March 25, 2012 | |||||||||||||
Income taxes included in other comprehensive income: | ||||||||||||||||
Change in fair value of interest rate hedges | $ | — | $ | — | $ | — | $ | 2 | ||||||||
Reclassification of unrealized loss on interest rate hedges into earnings | — | — | — | 3 | ||||||||||||
Change in fair value of commodity hedges | — | — | (2 | ) | 2 | |||||||||||
Reclassification of unrealized gain on commodity hedges into earnings | — | — | — | (1 | ) | |||||||||||
Actuarial gain (loss) relating to postretirement benefits | 1 | (15 | ) | (13 | ) | — | ||||||||||
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings | — | — | — | 1 | ||||||||||||
$ | 1 | $ | (15 | ) | $ | (15 | ) | $ | 7 |
December 31, | |||||||
2014 | 2013 | ||||||
Other postretirement plan - net actuarial gain and prior service costs, net | $ | — | $ | 3 | |||
Total accumulated other comprehensive income, net of tax | $ | — | $ | 3 |
7. | DEBT OBLIGATIONS: |
December 31, | |||||||
2014 | 2013 | ||||||
6.20% Senior Notes due 2017 | $ | 300 | $ | 300 | |||
8.125% Senior Notes due 2019 | 150 | 150 | |||||
7.00% Senior Notes due 2018 | 400 | 400 | |||||
7.6% Senior Notes due 2024 | 82 | 82 | |||||
7.00% Senior Notes due 2029 | 66 | 66 | |||||
8.25% Senior Notes due 2029 | 33 | 33 | |||||
Floating Rate Junior Subordinated Notes due 2066 | 54 | 54 | |||||
Note payable to related party - ETP | — | 1,090 | |||||
Other long term debt | 6 | 7 | |||||
Unamortized fair value adjustments | 99 | 155 | |||||
Total debt outstanding | 1,190 | 2,337 | |||||
Less: Current maturities of long-term debt | 1 | 1 | |||||
Total long-term debt, less current maturities | $ | 1,189 | $ | 2,336 |
Years Ended December 31, | ||||
2015 | $ | — | ||
2016 | — | |||
2017 | 300 | |||
2018 | 400 | |||
2019 | 150 | |||
Thereafter | 241 | |||
Total | $ | 1,091 |
8. | RETIREMENT BENEFITS: |
December 31, | |||||||
2014 | 2013 | ||||||
Change in benefit obligation: | |||||||
Benefit obligation at beginning of period | $ | 25 | $ | 41 | |||
Service cost | — | — | |||||
Interest cost | 1 | 1 | |||||
Amendments | — | 1 | |||||
Actuarial (gain) loss | 1 | (16 | ) | ||||
Benefits paid, net | (2 | ) | (2 | ) | |||
Dispositions | (1 | ) | — | ||||
Benefit obligation at end of period | $ | 24 | $ | 25 | |||
Change in plan assets: | |||||||
Fair value of plan assets at beginning of period | $ | 110 | $ | 96 | |||
Return on plan assets and other | 4 | 8 | |||||
Employer contributions | 7 | 8 | |||||
Benefits paid, net | (2 | ) | (2 | ) | |||
Dispositions | (5 | ) | — | ||||
Fair value of plan assets at end of period | $ | 114 | $ | 110 | |||
Amount (overfunded) underfunded at end of period (1) | $ | (90 | ) | $ | (85 | ) | |
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of: | |||||||
Net actuarial loss | $ | (16 | ) | $ | (20 | ) | |
Prior service cost | 15 | 17 | |||||
$ | (1 | ) | $ | (3 | ) |
(1) | Underfunded balance is recognized as a non-current liability in the consolidated balance sheets. Overfunded balance is recognized as a non-current asset in the consolidated balance sheets. |
Successor | Predecessor | |||||||||||||||
Year Ended December 31, 2014 | Year Ended December 31, 2013 | Period from Acquisition (March 26, 2012) to December 31, 2012 | Period from January 1, 2012 to March 25, 2012 | |||||||||||||
Service cost | $ | — | $ | — | $ | — | $ | 1 | ||||||||
Interest cost | 1 | 1 | 1 | 1 | ||||||||||||
Expected return on plan assets | (5 | ) | (5 | ) | (4 | ) | (1 | ) | ||||||||
Prior service credit amortization | 1 | 1 | — | (1 | ) | |||||||||||
Actuarial loss amortization | (1 | ) | (1 | ) | — | — | ||||||||||
Curtailment recognition (1) | — | — | (15 | ) | — | |||||||||||
Net periodic benefit cost | $ | (4 | ) | $ | (4 | ) | $ | (18 | ) | $ | — |
(1) | Subsequent to the ETE Merger, the Company amended certain of its other postretirement employee benefit plans to prospectively restrict participation in the plans for certain active employees. The plan amendments resulted in the plans becoming currently over-funded and, accordingly, the Company recorded a gross pre-tax curtailment gain of $75 million, $60 million of which is subject to refund to customers; thus, the net curtailment gain recognition was $15 million. |
Successor | Predecessor | |||||||||||
Year Ended December 31, 2014 | Year Ended December 31, 2013 | Period from Acquisition (March 26, 2012) to December 31, 2012 | Period from January 1, 2012 to March 25, 2012 | |||||||||
Discount rate | 4.29 | % | 3.66 | % | 4.02 | % | 4.24 | % | ||||
Expected return on assets: | ||||||||||||
Tax exempt accounts | 7.00 | % | 7.00 | % | 7.00 | % | 7.00 | % | ||||
Taxable accounts | 4.50 | % | 4.50 | % | 4.50 | % | 4.50 | % |
December 31, | |||||
2014 | 2013 | ||||
Health care cost trend rate | 7.60 | % | 8.06 | % | |
Rate to which the cost trend is assumed to decline (the ultimate trend rate) | 4.90 | % | 4.91 | % | |
Year that the rate reaches the ultimate trend rate | 2021 | 2021 |
One Percentage Point Increase | One Percentage Point Decrease | ||||||
Effect on accumulated postretirement benefit obligation | $ | 1 | $ | (1 | ) |
December 31, | |||||||
2014 | 2013 | ||||||
Cash and cash equivalents | $ | 3 | $ | 3 | |||
Mutual fund (1) | 111 | 107 | |||||
Total | $ | 114 | $ | 110 |
(1) | This fund of funds invests primarily in a diversified portfolio of equity, fixed income and short-term mutual funds. As of December 31, 2014, the fund was primarily comprised of approximately 38% equities, 52% fixed income securities and 10% cash. As of December 31, 2013, the fund was primarily comprised of approximately 32% equities, 55% fixed income securities, 7% cash and 6% in other investments. |
Years | Expected Benefit Payments | |||
2015 | $ | 2 | ||
2016 | 2 | |||
2017 | 2 | |||
2018 | 1 | |||
2019 | 1 | |||
2020 – 2024 | 6 |
Successor | Predecessor | |||||||||||||||
Year Ended December 31, 2014 | Year Ended December 31, 2013 | Period from Acquisition (March 26, 2012) to December 31, 2012 | Period from January 1, 2012 to March 25, 2012 | |||||||||||||
Current expense (benefit): | ||||||||||||||||
Federal | $ | 261 | $ | (52 | ) | $ | (43 | ) | $ | — | ||||||
State | 24 | (7 | ) | 3 | (1 | ) | ||||||||||
Total | 285 | (59 | ) | (40 | ) | (1 | ) | |||||||||
Deferred expense (benefit): | ||||||||||||||||
Federal | $ | (114 | ) | $ | 119 | $ | 81 | $ | 10 | |||||||
State | (25 | ) | 38 | (2 | ) | 3 | ||||||||||
Total | (139 | ) | 157 | 79 | 13 | |||||||||||
Total income tax expense | $ | 146 | $ | 98 | $ | 39 | $ | 12 |
Successor | Predecessor | |||||||||||||||
Year Ended December 31, 2014 | Year Ended December 31, 2013 | Period from Acquisition (March 26, 2012) to December 31, 2012 | Period from January 1, 2012 to March 25, 2012 | |||||||||||||
Computed statutory income tax expense (benefit) at 35% | $ | 50 | $ | (165 | ) | $ | 17 | $ | 16 | |||||||
Changes in income taxes resulting from: | ||||||||||||||||
Earnings from unconsolidated investments related to anticipated receipt of dividends | — | — | 5 | (5 | ) | |||||||||||
Non-deductible executive compensation | — | — | 18 | — | ||||||||||||
Premium on debt retirement | (10 | ) | — | — | — | |||||||||||
State income taxes, net of federal income tax benefit | 4 | 21 | 1 | 1 | ||||||||||||
Non-deductible goodwill impairment | — | 241 | — | — | ||||||||||||
Non-deductible goodwill included in the Lake Charles LNG Transaction | 105 | — | — | — | ||||||||||||
Other | (3 | ) | 1 | (2 | ) | — | ||||||||||
Income tax expense | $ | 146 | $ | 98 | $ | 39 | $ | 12 |
December 31, | |||||||
2014 | 2013 | ||||||
Deferred income tax assets: | |||||||
Other postretirement benefits | $ | 5 | $ | 5 | |||
Debt amortization | 40 | 67 | |||||
Other | 26 | 40 | |||||
Total deferred income tax assets | 71 | 112 | |||||
Valuation allowance | (2 | ) | — | ||||
Net deferred income tax assets | $ | 69 | $ | 112 | |||
Deferred income tax liabilities: | |||||||
Property, plant and equipment | $ | (776 | ) | $ | (956 | ) | |
Investment in unconsolidated affiliates | (795 | ) | (793 | ) | |||
Other | (6 | ) | (16 | ) | |||
Total deferred income tax liabilities | (1,577 | ) | (1,765 | ) | |||
Net deferred income tax liability | (1,508 | ) | (1,653 | ) | |||
Less current income tax assets | 3 | 6 | |||||
Accumulated deferred income taxes | $ | (1,511 | ) | $ | (1,659 | ) |
10. | PRICE RISK MANAGEMENT ASSETS AND LIABILITIES: |
Fair Value | |||||||||||||||
Asset Derivatives | Liability Derivatives | ||||||||||||||
Balance Sheet Location | December 31, 2014 | December 31, 2013 | December 31, 2014 | December 31, 2013 | |||||||||||
Economic Hedges: | |||||||||||||||
Interest rate contracts: | |||||||||||||||
Price risk management liabilities | $ | — | $ | — | $ | — | $ | 10 | |||||||
Non-current price management liabilities | — | — | — | 15 | |||||||||||
Total | $ | — | $ | — | $ | — | $ | 25 |
Successor | Predecessor | |||||||||||||||
Year Ended December 31, 2014 | Year Ended December 31, 2013 | Period from Acquisition (March 26, 2012) to December 31, 2012 | Period from January 1, 2012 to March 25, 2012 | |||||||||||||
Cash Flow Hedges: | ||||||||||||||||
Interest rate contracts: | ||||||||||||||||
Change in fair value – increase in accumulated other comprehensive income | $ | — | $ | — | $ | — | $ | 6 | ||||||||
Reclassification of unrealized loss from accumulated other comprehensive income – increase of interest expense | — | — | — | 8 | ||||||||||||
Commodity contracts — Gathering and Processing: | ||||||||||||||||
Change in fair value – increase (decrease) in accumulated other comprehensive income | — | (3 | ) | (6 | ) | 5 | ||||||||||
Reclassification of unrealized gain from accumulated other comprehensive income | — | — | 1 | 2 | ||||||||||||
Economic Hedges: | ||||||||||||||||
Interest rate contracts: | ||||||||||||||||
Change in fair value — increase (decrease) in interest expense | (7 | ) | 29 | 12 | — | |||||||||||
Commodity contracts: | ||||||||||||||||
Change in fair value — decrease in deferred natural gas purchases | — | (7 | ) | (32 | ) | (2 | ) |
11. | FAIR VALUE MEASUREMENT: |
Fair Value as of | Fair Value Measurements at December 31, 2013 Using Fair Value Hierarchy | ||||||||||
December 31, 2013 | Level 1 | Level 2 | |||||||||
Assets: | |||||||||||
Total | $ | — | $ | — | $ | — | |||||
Liabilities: | |||||||||||
Interest rate swaps | $ | 25 | $ | — | $ | 25 | |||||
Total | $ | 25 | $ | — | $ | 25 |
12. | PROPERTY, PLANT AND EQUIPMENT: |
December 31, | ||||||||||
Lives in Years | 2014 | 2013 | ||||||||
Land and improvements | $ | 8 | $ | 8 | ||||||
Buildings and improvements | 6 – 22 | 340 | 336 | |||||||
Pipelines and equipment | 5 – 46 | 2,353 | 2,273 | |||||||
Natural gas storage facilities | 5 – 46 | 323 | 314 | |||||||
Tanks and other equipment | 20 – 40 | — | 955 | |||||||
Vehicles | 5 | 23 | 23 | |||||||
Right of way | 36 – 40 | 23 | 23 | |||||||
Furniture and fixtures | 5 – 12 | 33 | 34 | |||||||
Linepack | 57 | 57 | ||||||||
Other | 2 – 19 | 192 | 185 | |||||||
Construction work in progress | 43 | 70 | ||||||||
Total property, plant and equipment | 3,395 | 4,278 | ||||||||
Accumulated depreciation and amortization | (269 | ) | (216 | ) | ||||||
Net property, plant and equipment | $ | 3,126 | $ | 4,062 |
13. | ASSET RETIREMENT OBLIGATIONS: |
Successor | Predecessor | |||||||||||||||
Year Ended December 31, 2014 | Year Ended December 31, 2013 | Period from Acquisition (March 26, 2012) to December 31, 2012 | Period from January 1, 2012 to March 25, 2012 | |||||||||||||
Beginning balance | $ | 55 | $ | 46 | $ | 46 | $ | 46 | ||||||||
Revisions | 3 | 11 | 3 | — | ||||||||||||
Settled | (3 | ) | (1 | ) | (5 | ) | — | |||||||||
Disposals | — | (4 | ) | — | — | |||||||||||
Accretion expense | 3 | 3 | 2 | — | ||||||||||||
Ending balance | $ | 58 | $ | 55 | $ | 46 | $ | 46 |
14. | REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES: |
December 31, | |||||||
2014 | 2013 | ||||||
Current | $ | 1 | $ | 2 | |||
Non-current | 3 | 3 | |||||
Total environmental liabilities | $ | 4 | $ | 5 |
15. | QUARTERLY FINANCIAL DATA (UNAUDITED): |
Quarters Ended | |||||||||||||||||||
March 31, 2014 | June 30, 2014 | September 30, 2014 | December 31, 2014 | Total | |||||||||||||||
Operating revenues | $ | 178 | $ | 128 | $ | 132 | $ | 143 | $ | 581 | |||||||||
Operating income | 90 | 34 | 31 | 38 | 193 | ||||||||||||||
Net income (loss) | (35 | ) | 16 | 23 | (7 | ) | (3 | ) | |||||||||||
Net income (loss) attributable to partners | (41 | ) | 16 | 23 | (7 | ) | (9 | ) | |||||||||||
March 31, 2013 | June 30, 2013 | September 30, 2013 | December 31, 2013 | Total | |||||||||||||||
Operating revenues | $ | 393 | $ | 316 | $ | 182 | $ | 194 | $ | 1,085 | |||||||||
Operating income (loss) | 55 | 115 | 67 | (619 | ) | (382 | ) | ||||||||||||
Net income (loss) | 36 | 40 | 58 | (669 | ) | (535 | ) | ||||||||||||
Net income (loss) attributable to partners | 42 | 69 | 37 | (647 | ) | (499 | ) |
Successor | Predecessor | |||||||||||||||||||||||
Years Ended December 31, | Period from Acquisition (March 26, 2012) to December 31, 2012 | Period from January 1, 2012 to March 25, 2012 | Years Ended December 31, | |||||||||||||||||||||
2014 | 2013 | 2011 | 2010 | |||||||||||||||||||||
Fixed Charges: | ||||||||||||||||||||||||
Interest expense, net | $ | 66 | $ | 111 | $ | 131 | $ | 50 | $ | 217 | $ | 210 | ||||||||||||
Net amortization of debt discount, premium and issuance expense | (22 | ) | (28 | ) | (24 | ) | 2 | 6 | 7 | |||||||||||||||
Capitalized interest | 2 | 1 | 1 | — | 1 | 7 | ||||||||||||||||||
Interest charges included in rental expense | 1 | 2 | 5 | 2 | 7 | 6 | ||||||||||||||||||
Total fixed charges | $ | 47 | $ | 86 | $ | 113 | $ | 54 | $ | 231 | $ | 230 | ||||||||||||
Earnings: | ||||||||||||||||||||||||
Income (loss) from continuing operations before income tax expense and noncontrolling interest | $ | 143 | $ | (472 | ) | $ | 50 | $ | 45 | $ | 294 | $ | 278 | |||||||||||
Less: equity in earnings (losses) of unconsolidated affiliates | (12 | ) | 15 | (7 | ) | 16 | 99 | 105 | ||||||||||||||||
Total earnings | 155 | (487 | ) | 57 | 29 | 195 | 173 | |||||||||||||||||
Add: | ||||||||||||||||||||||||
Fixed Charges | 47 | 86 | 113 | 54 | 231 | 230 | ||||||||||||||||||
Distributed income of equity investees | 72 | 54 | 6 | — | 3 | 4 | ||||||||||||||||||
Less: | ||||||||||||||||||||||||
Interest capitalized | (2 | ) | (1 | ) | (1 | ) | — | (1 | ) | (7 | ) | |||||||||||||
Income Available for Fixed Charges | $ | 272 | $ | (348 | ) | $ | 175 | $ | 83 | $ | 428 | $ | 400 | |||||||||||
Ratio of earnings to fixed charges | 5.79 | (a) | 1.55 | 1.54 | 1.85 | 1.74 |
(a) | For the year ended December 31, 2013, fixed charges exceeded earnings by $434 million. In 2013, Panhandle Eastern Pipe Line Company, LP recognized a $689 million goodwill impairment charge associated with the Lake Charles LNG reporting unit. |
1. | I have reviewed this annual report on Form 10-K of Panhandle Eastern Pipe Line Company, LP (the “registrant”); |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c. | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d. | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize, and report financial information; and |
b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Kelcy L. Warren | |
Kelcy L. Warren | |
Chief Executive Officer |
1. | I have reviewed this annual report on Form 10-K of Panhandle Eastern Pipe Line Company, LP (the “registrant”); |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c. | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d. | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize, and report financial information; and |
b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Martin Salinas, Jr. | |
Martin Salinas, Jr. | |
Chief Financial Officer |
(1) | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ Kelcy L. Warren | |
Kelcy L. Warren | |
Chief Executive Officer |
(1) | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ Martin Salinas, Jr. | |
Martin Salinas, Jr. | |
Chief Financial Officer |
Page | |
Name | Definition or Description | |
2018 Notes | $600 million of 6.875% senior notes with original maturity on December 1, 2018 | |
AOCI | Accumulated Other Comprehensive Income (Loss) | |
Aqua - PVR | Aqua - PVR Water Services, LLC | |
ARO | Asset Retirement Obligation | |
APM | Anadarko Pecos Midstream LLC | |
Barclays | Barclays Capital Inc. | |
bps | Basis points | |
Citi | Citigroup Global Markets Inc. | |
CM | Chesapeake West Texas Processing, L.L.C. | |
Coal Handling | Coal Handling Solutions LLC, Kingsport Handling LLC, and Kingsport Services LLC, now known as Materials Handling Solutions LLC | |
Eagle Rock | Eagle Rock Energy Partners, L.P. | |
EFS Haynesville | EFS Haynesville, LLC, a wholly-owned subsidiary of GECC | |
ELG | Edwards Lime Gathering LLC and its wholly-owned subsidiaries, ELG Oil LLC and ELG Utility LLC | |
EPD | Enterprise Products Partners L.P. | |
ETC | Energy Transfer Company, the name assumed by La Grange Acquisition, L.P. for conducting business and shared services, a wholly-owned subsidiary of ETP | |
ETE | Energy Transfer Equity, L.P. | |
ETE Common Holdings | ETE Common Holdings, LLC, a wholly-owned subsidiary of ETE | |
ETE GP | ETE GP Acquirer LLC | |
ETP | Energy Transfer Partners, L.P. | |
ETP GP | Energy Transfer Partners GP, LP | |
Exchange Act | Securities Exchange Act of 1934, as amended | |
FASB | Financial Accounting Standards Board | |
FASB ASC | FASB Accounting Standards Codification | |
Finance Corp. | Regency Energy Finance Corp., a wholly-owned subsidiary of the Partnership | |
GAAP | Accounting principles generally accepted in the United States of America | |
General Partner | Regency GP LP, the general partner of the Partnership, or Regency GP LLC, the general partner of Regency GP LP, which effectively manages the business and affairs of the Partnership through its board of directors and Regency Employees Management LLC | |
Grey Ranch | Grey Ranch Plant LP, a former joint venture of the Partnership | |
Gulf States | Gulf States Transmission LLC, a wholly-owned subsidiary of the Partnership | |
Holdco | ETP Holdco Corporation | |
Hoover | Hoover Energy Partners, LP | |
HPC | RIGS Haynesville Partnership Co. and its wholly-owned subsidiary, Regency Intrastate Gas LP | |
IDRs | Incentive Distribution Rights | |
IRS | Internal Revenue Service | |
KMP | Kinder Morgan Energy Partners, L.P. | |
LDH | LDH Energy Asset Holdings LLC | |
LIBOR | London Interbank Offered Rate | |
Lone Star | Lone Star NGL LLC | |
LTIP | Long-Term Incentive Plan |
Name | Definition or Description | |
MEP | Midcontinent Express Pipeline LLC | |
Mi Vida JV | Mi Vida JV LLC | |
MLP | Master Limited Partnership | |
NGLs | Natural gas liquids, including ethane, propane, normal butane, iso butane and natural gasoline | |
NMED | New Mexico Environmental Development | |
NYSE | New York Stock Exchange | |
ORS | Ohio River System LLC | |
PADEP | Pennsylvania Department of Environmental Protection | |
Partnership | Regency Energy Partners LP | |
PEPL | Panhandle Eastern Pipe Line Company, LP | |
PEPL Holdings | PEPL Holdings, LLC, a former wholly-owned subsidiary of Southern Union that merged into PEPL | |
PVR | PVR Partners, L.P. | |
Ranch JV | Ranch Westex JV LLC | |
Regency Western | Regency Western G&P LLC, a wholly-owned subsidiary of the Partnership | |
RGS | Regency Gas Services, LP, a wholly-owned subsidiary of the Partnership | |
RIGS | Regency Intrastate Gas System | |
SEC | Securities and Exchange Commission | |
Securities Act | Securities Act of 1933, as amended | |
Senior Notes | The collective of 2019 Notes, 2020 Notes, 2020 PVR Notes, 2021 Notes, 2021 PVR Notes, 2022 Notes, October 2022 Notes, 2023 4.5% Notes and 2023 5.5% Notes | |
Series A Preferred Units | Series A convertible redeemable preferred units | |
Services Co. | ETE Services Company, LLC | |
Southern Union | Southern Union Company | |
SUGS | Southern Union Gas Services | |
SUN | Sunoco LP (formerly known as Susser, L.P.) | |
Sweeny JV | Sweeny Gathering, L.P. | |
SXL | Sunoco Logistics Partners L.P. | |
TCEQ | Texas Commission on Environmental Quality | |
U.S. | United States | |
Wells Fargo | Wells Fargo Securities, LLC | |
WTI | West Texas Intermediate Crude |
December 31, | |||||||
2014 | 2013 | ||||||
ASSETS | |||||||
Current Assets: | |||||||
Cash and cash equivalents | $ | 24 | $ | 19 | |||
Trade accounts receivable, net of allowance for doubtful accounts of $7 and $1 | 483 | 292 | |||||
Related party receivables | 45 | 28 | |||||
Inventories | 67 | 42 | |||||
Derivative assets | 75 | 3 | |||||
Other current assets | 9 | 16 | |||||
Total current assets | 703 | 400 | |||||
Property, Plant and Equipment: | |||||||
Gathering and transmission systems | 5,207 | 1,671 | |||||
Compression equipment | 2,378 | 1,627 | |||||
Gas plants and buildings | 386 | 825 | |||||
Other property, plant and equipment | 679 | 414 | |||||
Natural resources | 454 | — | |||||
Construction-in-progress | 1,156 | 513 | |||||
Total property, plant and equipment | 10,260 | 5,050 | |||||
Less accumulated depreciation and depletion | (1,043 | ) | (632 | ) | |||
Property, plant and equipment, net | 9,217 | 4,418 | |||||
Other Assets: | |||||||
Investments in unconsolidated affiliates | 2,418 | 2,097 | |||||
Other, net of accumulated amortization of debt issuance costs of $28 and $24 | 103 | 57 | |||||
Total other assets | 2,521 | 2,154 | |||||
Intangible Assets and Goodwill: | |||||||
Intangible assets, net of accumulated amortization of $212 and $107 | 3,439 | 682 | |||||
Goodwill | 1,223 | 1,128 | |||||
Total intangible assets and goodwill | 4,662 | 1,810 | |||||
TOTAL ASSETS | $ | 17,103 | $ | 8,782 |
December 31, | |||||||
2014 | 2013 | ||||||
LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST | |||||||
Current Liabilities: | |||||||
Drafts payable | $ | 15 | $ | 26 | |||
Trade accounts payable | 529 | 291 | |||||
Related party payables | 64 | 69 | |||||
Accrued expenses | 43 | 25 | |||||
Accrued interest | 81 | 38 | |||||
Other current liabilities | 24 | 26 | |||||
Total current liabilities | 756 | 475 | |||||
Long-term derivative liabilities | 16 | 19 | |||||
Other long-term liabilities | 72 | 30 | |||||
Long-term debt, net | 6,641 | 3,310 | |||||
Commitments and contingencies | |||||||
Series A Preferred Units, redemption amount of $38 and $38 | 33 | 32 | |||||
Partners’ Capital and Noncontrolling Interest: | |||||||
Common units (412,681,151 and 214,287,955 units authorized; 409,406,482 and 210,850,232 units issued and outstanding at December 31, 2014 and 2013) | 8,531 | 3,886 | |||||
Class F units (6,274,483 units authorized, issued and outstanding at December 31, 2014 and 2013) | 153 | 146 | |||||
General partner interest | 781 | 782 | |||||
Total partners’ capital | 9,465 | 4,814 | |||||
Noncontrolling interest | 120 | 102 | |||||
Total partners’ capital and noncontrolling interest | 9,585 | 4,916 | |||||
TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST | $ | 17,103 | $ | 8,782 |
Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
REVENUES | |||||||||||
Gas sales, including related party amounts of $80, $71, and $42 | $ | 1,903 | $ | 826 | $ | 508 | |||||
NGL sales, including related party amounts of $282, $81, and $28 | 1,741 | 1,053 | 991 | ||||||||
Gathering, transportation and other fees, including related party amounts of $23, $26, and $29 | 989 | 545 | 401 | ||||||||
Net realized and unrealized gain (loss) from derivatives | 93 | (8 | ) | 23 | |||||||
Other | 225 | 105 | 77 | ||||||||
Total revenues | 4,951 | 2,521 | 2,000 | ||||||||
OPERATING COSTS AND EXPENSES | |||||||||||
Cost of sales, including related party amounts of $66, $56, and $35 | 3,452 | 1,793 | 1,387 | ||||||||
Operation and maintenance | 448 | 296 | 228 | ||||||||
General and administrative | 158 | 88 | 100 | ||||||||
(Gain) loss on asset sales, net | (1 | ) | 2 | 3 | |||||||
Depreciation, depletion and amortization | 541 | 287 | 252 | ||||||||
Goodwill impairment | 370 | — | — | ||||||||
Total operating costs and expenses | 4,968 | 2,466 | 1,970 | ||||||||
OPERATING (LOSS) INCOME | (17 | ) | 55 | 30 | |||||||
Income from unconsolidated affiliates | 195 | 135 | 105 | ||||||||
Interest expense, net | (304 | ) | (164 | ) | (122 | ) | |||||
Loss on debt refinancing, net | (25 | ) | (7 | ) | (8 | ) | |||||
Other income and deductions, net | 12 | 7 | 29 | ||||||||
(LOSS) INCOME BEFORE INCOME TAXES | (139 | ) | 26 | 34 | |||||||
Income tax expense (benefit) | 3 | (1 | ) | — | |||||||
NET (LOSS) INCOME | $ | (142 | ) | $ | 27 | $ | 34 | ||||
Net income attributable to noncontrolling interest | (15 | ) | (8 | ) | (2 | ) | |||||
NET (LOSS) INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP | $ | (157 | ) | $ | 19 | $ | 32 | ||||
Amounts attributable to Series A preferred units | 4 | 6 | 10 | ||||||||
General partner’s interest, including IDRs | 31 | 11 | 9 | ||||||||
Beneficial conversion feature for Class F units | 7 | 4 | — | ||||||||
Pre-acquisition loss from SUGS allocated to predecessor equity | — | (36 | ) | (14 | ) | ||||||
Limited partners’ interest in net (loss) income | $ | (199 | ) | $ | 34 | $ | 27 | ||||
Basic and diluted (loss) income per common unit: | |||||||||||
Limited partners’ interest in net (loss) income | $ | (199 | ) | $ | 34 | $ | 27 | ||||
Weighted average number of common units outstanding | 348,070,121 | 196,227,348 | 167,492,735 | ||||||||
Basic (loss) income per common unit | $ | (0.57 | ) | $ | 0.17 | $ | 0.16 | ||||
Diluted (loss) income per common unit | $ | (0.57 | ) | $ | 0.17 | $ | 0.13 | ||||
Distributions per common unit | $ | 1.975 | $ | 1.87 | $ | 1.84 | |||||
Amount allocated to beneficial conversion feature for Class F units | $ | 7 | $ | 4 | $ | — | |||||
Total number of Class F units outstanding | 6,274,483 | 6,274,483 | — | ||||||||
Income per Class F unit due to beneficial conversion feature | $ | 1.08 | $ | 0.72 | $ | — |
Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
Net (loss) income | $ | (142 | ) | $ | 27 | $ | 34 | ||||
Other comprehensive income: | |||||||||||
Net cash flow hedge amounts reclassified to earnings | — | — | 6 | ||||||||
Change in fair value of cash flow hedges | — | — | (4 | ) | |||||||
Total other comprehensive income | $ | — | $ | — | $ | 2 | |||||
Comprehensive (loss) income | $ | (142 | ) | $ | 27 | $ | 36 | ||||
Comprehensive income attributable to noncontrolling interest | 15 | 8 | 2 | ||||||||
Comprehensive (loss) income attributable to Regency Energy Partners LP | $ | (157 | ) | $ | 19 | $ | 34 |
Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
OPERATING ACTIVITIES | |||||||||||
Net (loss) income | $ | (142 | ) | $ | 27 | $ | 34 | ||||
Reconciliation of net (loss) income to net cash flows provided by operating activities: | |||||||||||
Depreciation, depletion and amortization, including debt issuance cost amortization and bond premium write-off and amortization | 525 | 293 | 259 | ||||||||
Income from unconsolidated affiliates | (195 | ) | (135 | ) | (105 | ) | |||||
Derivative valuation changes | (93 | ) | 6 | (12 | ) | ||||||
(Gain) loss on asset sales, net | (1 | ) | 2 | 3 | |||||||
Unit-based compensation expenses | 10 | 7 | 5 | ||||||||
Revaluation of unconsolidated affiliate upon acquisition | (6 | ) | — | — | |||||||
Goodwill impairment | 370 | — | — | ||||||||
Cash flow changes in current assets and liabilities: | |||||||||||
Trade accounts receivable and related party receivables | 28 | (96 | ) | — | |||||||
Other current assets and other current liabilities | 34 | (54 | ) | 10 | |||||||
Trade accounts payable and related party payables | (16 | ) | 119 | 18 | |||||||
Distributions of earnings received from unconsolidated affiliates | 204 | 142 | 121 | ||||||||
Cash flow changes in other assets and liabilities | 1 | 125 | (9 | ) | |||||||
Net cash flows provided by operating activities | 719 | 436 | 324 | ||||||||
INVESTING ACTIVITIES | |||||||||||
Capital expenditures | (1,088 | ) | (1,034 | ) | (560 | ) | |||||
Contributions to unconsolidated affiliates | (355 | ) | (148 | ) | (356 | ) | |||||
Distributions in excess of earnings of unconsolidated affiliates | 68 | 249 | 83 | ||||||||
Acquisitions, net of cash received | (805 | ) | (475 | ) | — | ||||||
Proceeds from asset sales | 11 | 15 | 26 | ||||||||
Net cash flows used in investing activities | (2,169 | ) | (1,393 | ) | (807 | ) | |||||
FINANCING ACTIVITIES | |||||||||||
Borrowings (repayments) under revolving credit facility, net | 380 | 318 | (140 | ) | |||||||
Proceeds from issuance of senior notes | 1,580 | 1,000 | 700 | ||||||||
Redemptions of senior notes | (983 | ) | (163 | ) | (88 | ) | |||||
Debt issuance costs | (31 | ) | (24 | ) | (15 | ) | |||||
Partner distributions and distributions on unvested unit awards | (706 | ) | (386 | ) | (322 | ) | |||||
Noncontrolling interest contributions, net of distributions | 3 | 17 | 42 | ||||||||
Contributions from previous parent | — | — | 51 | ||||||||
Drafts payable | (11 | ) | 18 | 4 | |||||||
Common units issued under unit offerings, equity distribution program and LTIP, net of issuance costs, forfeitures and tax withholding | 1,227 | 149 | 311 | ||||||||
Distributions to Series A Preferred Units | (4 | ) | (6 | ) | (8 | ) | |||||
Net cash flows provided by financing activities | 1,455 | 923 | 535 |
Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
Net change in cash and cash equivalents | 5 | (34 | ) | 52 | |||||||
Cash and cash equivalents at beginning of period | 19 | 53 | 1 | ||||||||
Cash and cash equivalents at end of period | $ | 24 | $ | 19 | $ | 53 | |||||
Supplemental cash flow information: | |||||||||||
Accrued capital expenditures | $ | 102 | $ | 60 | $ | 136 | |||||
Issuance of Class F and common units in connection with SUGS Acquisition | — | 961 | — | ||||||||
Issuance of common units in connection with PVR, Hoover, and Eagle Rock acquisitions | 4,281 | — | — | ||||||||
Long-term debt assumed in PVR Acquisition | 1,887 | — | — | ||||||||
Long-term debt exchanged in connection with the Eagle Rock Midstream Acquisition | 499 | — | — | ||||||||
Interest paid, net of amounts capitalized | 303 | 146 | 112 | ||||||||
Accrued capital contribution to unconsolidated affiliate | — | 13 | 23 |
Regency Energy Partners LP | |||||||||||||||||||||||||||
Common Units | Class F Units | General Partner Interest | Predecessor Equity | AOCI | Non-controlling Interest | Total | |||||||||||||||||||||
Balance - December 31, 2011 | $ | 3,173 | $ | — | $ | 330 | $ | — | $ | (5 | ) | $ | 33 | $ | 3,531 | ||||||||||||
Common unit offerings, net of costs | 297 | — | — | — | — | — | 297 | ||||||||||||||||||||
Issuance of common units under equity distribution program, net of costs | 15 | — | — | — | — | — | 15 | ||||||||||||||||||||
Common units issued under LTIP, net of forfeitures and tax withholding | (1 | ) | — | — | — | — | — | (1 | ) | ||||||||||||||||||
Unit-based compensation expenses | 5 | — | — | — | — | — | 5 | ||||||||||||||||||||
Partner distributions | (309 | ) | — | (13 | ) | — | — | — | (322 | ) | |||||||||||||||||
Net income (loss) | 37 | — | 9 | (14 | ) | — | 2 | 34 | |||||||||||||||||||
Noncontrolling interest contributions, net of distributions | — | — | — | — | — | 42 | 42 | ||||||||||||||||||||
Distributions to Series A Preferred Units | (8 | ) | — | — | — | — | — | (8 | ) | ||||||||||||||||||
Accretion of Series A Preferred Units | (2 | ) | — | — | — | — | — | (2 | ) | ||||||||||||||||||
Net cash flow hedge amounts reclassified to earnings | — | — | — | — | 5 | — | 5 | ||||||||||||||||||||
Contribution of net investment to unitholders | — | — | — | 1,747 | (3 | ) | — | 1,744 | |||||||||||||||||||
Balance - December 31, 2012 | $ | 3,207 | $ | — | $ | 326 | $ | 1,733 | $ | (3 | ) | $ | 77 | $ | 5,340 | ||||||||||||
Contribution of net investment to the Partnership | — | — | 1,925 | (1,928 | ) | 3 | — | — | |||||||||||||||||||
Issuance of common units in connection with the SUGS Acquisition, net of costs | 819 | — | (819 | ) | — | — | — | — | |||||||||||||||||||
Issuance of Class F units in connection with the SUGS Acquisition, net of costs | — | 142 | (142 | ) | — | — | — | — | |||||||||||||||||||
Contribution of assets between entities under common control below historical cost | — | — | (504 | ) | 231 | — | — | (273 | ) | ||||||||||||||||||
Issuance of common units under equity distribution program, net of costs | 149 | — | — | — | — | — | 149 | ||||||||||||||||||||
Conversion of Series A Preferred Units for common units | 41 | — | — | — | — | — | 41 | ||||||||||||||||||||
Unit-based compensation expenses | 7 | — | — | — | — | — | 7 | ||||||||||||||||||||
Partner distributions and distributions on unvested unit awards | (371 | ) | — | (15 | ) | — | — | — | (386 | ) | |||||||||||||||||
Noncontrolling interest contributions, net of distributions | — | — | — | — | — | 17 | 17 | ||||||||||||||||||||
Net income (loss) | 40 | 4 | 11 | (36 | ) | — | 8 | 27 | |||||||||||||||||||
Distributions to Series A Preferred Units | (6 | ) | — | — | — | — | — | (6 | ) | ||||||||||||||||||
Balance - December 31, 2013 | $ | 3,886 | $ | 146 | $ | 782 | $ | — | $ | — | $ | 102 | $ | 4,916 |
Regency Energy Partners LP | |||||||||||||||||||
Common Units | Class F Units | General Partner Interest | Noncontrolling Interest | Total | |||||||||||||||
Balance - December 31, 2013 | $ | 3,886 | $ | 146 | $ | 782 | $ | 102 | $ | 4,916 | |||||||||
Issuance of common units under equity distribution program, net of costs | 428 | — | — | — | 428 | ||||||||||||||
Issuance of common units to ETE Common Holdings | 800 | — | — | — | 800 | ||||||||||||||
Issuance of common units in connection with Hoover Acquisition | 109 | — | — | — | 109 | ||||||||||||||
Issuance of common units in connection with PVR Acquisition | 3,906 | — | — | — | 3,906 | ||||||||||||||
Issuance of common units in connection with Eagle Rock Midstream Acquisition | 266 | — | — | — | 266 | ||||||||||||||
Common units issued under LTIP, net of forfeitures and tax withholding | (1 | ) | — | — | — | (1 | ) | ||||||||||||
Unit-based compensation expenses | 10 | — | — | — | 10 | ||||||||||||||
Partner distributions and distributions on unvested unit awards | (674 | ) | — | (32 | ) | — | (706 | ) | |||||||||||
Noncontrolling interest contributions, net of distributions | — | — | — | 3 | 3 | ||||||||||||||
Net (loss) income | (195 | ) | 7 | 31 | 15 | (142 | ) | ||||||||||||
Distributions to Series A Preferred Units | (4 | ) | — | — | — | (4 | ) | ||||||||||||
Balance - December 31, 2014 | $ | 8,531 | $ | 153 | $ | 781 | $ | 120 | $ | 9,585 |
Functional Class of Property | Useful Lives (Years) | |
Gathering and Transmission Systems | 20 - 40 | |
Compression Equipment | 2 - 30 | |
Gas Plants and Buildings | 5 - 20 | |
Other Property, Plant and Equipment | 3 - 15 |
Common | Class F | |||||
Balance - December 31, 2011 | 157,437,608 | — | ||||
Common unit offerings, net of costs | 12,650,000 | — | ||||
Issuance of common units under the equity distribution agreement, net of cost | 691,129 | — | ||||
Issuance of common units under LTIP, net of forfeitures and tax withholding | 172,720 | — | ||||
Balance - December 31, 2012 | 170,951,457 | — | ||||
Issuance of common units under LTIP, net of forfeitures and tax withholding | 184,995 | — | ||||
Issuance of common units under the equity distribution agreement, net of cost | 5,712,138 | — | ||||
Conversion of Series A preferred units for common units | 2,629,223 | — | ||||
Issuance of common units and Class F units in connection with SUGS Acquisition | 31,372,419 | (1) | 6,274,483 | (2) | ||
Balance - December 31, 2013 | 210,850,232 | 6,274,483 | ||||
Issuance of common units under LTIP, net of forfeitures and tax withholding | 163,054 | — | ||||
Issuance of common units under the equity distribution agreements | 14,827,919 | — | ||||
Issuance of common units in connection with Hoover Acquisition | 4,040,471 | — | ||||
Issuance of common units in connection with PVR Acquisition | 140,388,382 | — | ||||
Issuance of common units in connection with Eagle Rock Midstream Acquisition | 8,245,859 | — | ||||
Issuance of common units to ETE Common Holdings | 30,890,565 | — | ||||
Balance - December 31, 2014 | 409,406,482 | 6,274,483 |
(1) | ETE has agreed to forgo IDR payments on the Partnership common units issued with the SUGS Acquisition for twenty-four months post-transaction closing. |
(2) | The Class F units are not entitled to participate in the Partnership’s distributions or earnings for twenty-four months post-transaction closing. |
Distribution Date | Cash Distribution (per common unit) | |||
November 14, 2014 | $ | 0.5025 | ||
August 14, 2014 | 0.490 | |||
May 15, 2014 | 0.480 | |||
February 14, 2014 | 0.475 | |||
November 14, 2013 | $ | 0.470 | ||
August 14, 2013 | 0.465 | |||
May 13, 2013 | 0.460 | |||
February 14, 2013 | 0.460 |
Years Ended December 31, | ||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||||||||||
Loss (Numerator) | Units (Denominator) | Per-Unit Amount | Income (Numerator) | Units (Denominator) | Per-Unit Amount | Income (Numerator) | Units (Denominator) | Per-Unit Amount | ||||||||||||||||||||||||
Basic (loss) income per unit | ||||||||||||||||||||||||||||||||
Limited Partners’ interest in net (loss) income | $ | (199 | ) | 348,070,121 | $ | (0.57 | ) | $ | 34 | 196,227,348 | $ | 0.17 | $ | 27 | 167,492,735 | $ | 0.16 | |||||||||||||||
Effect of Dilutive Securities: | ||||||||||||||||||||||||||||||||
Common unit options | — | — | — | 22,714 | — | 10,854 | ||||||||||||||||||||||||||
Phantom units * | — | — | — | 357,230 | — | 223,325 | ||||||||||||||||||||||||||
Series A Preferred Units | — | — | — | 2,050,854 | (5 | ) | 4,658,700 | |||||||||||||||||||||||||
Diluted (loss) income per unit | $ | (199 | ) | 348,070,121 | $ | (0.57 | ) | $ | 34 | 198,658,146 | $ | 0.17 | $ | 22 | 172,385,614 | $ | 0.13 |
* | Amount assumes maximum conversion rate for market condition awards. |
Year Ended December 31, 2014 | ||
Common unit options | 25,959 | |
Phantom units | 469,264 | |
Series A Preferred Units | 2,059,503 |
Assets | At July 1, 2014 | ||
Current assets | $ | 120 | |
Property, plant and equipment | 1,295 | ||
Other long-term assets | 4 | ||
Goodwill (1) | 49 | ||
Total Assets Acquired | $ | 1,468 | |
Liabilities | |||
Current liabilities | $ | 116 | |
Long-term debt | 499 | ||
Long-term liabilities | 12 | ||
Total Liabilities Assumed | $ | 627 | |
Net Assets Acquired | $ | 841 |
Assets | At March 21, 2014 | ||
Current assets | $ | 149 | |
Gathering and transmission systems | 1,396 | ||
Compression equipment | 342 | ||
Gas plants and buildings | 110 | ||
Natural resources | 454 | ||
Other property, plant and equipment | 229 | ||
Construction in process | 185 | ||
Investments in unconsolidated affiliates | 62 | ||
Intangible assets | 2,717 | ||
Goodwill (1) | 370 | ||
Other long-term assets | 18 | ||
Total Assets Acquired | $ | 6,032 | |
Liabilities | |||
Current liabilities | $ | 168 | |
Long-term debt | 1,788 | ||
Premium related to senior notes | 99 | ||
Long-term liabilities | 30 | ||
Total Liabilities Assumed | $ | 2,085 | |
Net Assets Acquired | $ | 3,947 |
Assets | At February 3, 2014 | ||
Accounts receivable, net | $ | 5 | |
Gathering and transmission systems | 60 | ||
Compression equipment | 16 | ||
Gas plants and buildings | 12 | ||
Other property, plant, and equipment | 23 | ||
Construction in process | 6 | ||
Intangible assets | 148 | ||
Goodwill (1) | 30 | ||
Total Assets Acquired | $ | 300 | |
Liabilities | |||
Accounts payable and accrued liabilities | $ | 5 | |
Asset retirement obligation | 2 | ||
Total Liabilities Assumed | $ | 7 | |
Net Assets Acquired | $ | 293 |
Years Ended December 31, | |||||||
2014 | 2013 | ||||||
Revenues | $ | 5,780 | $ | 4,695 | |||
Net loss attributable to the Partnership | (252 | ) | (195 | ) | |||
Basic net loss per Limited Partner unit | $ | (0.76 | ) | $ | (0.50 | ) | |
Diluted net loss per Limited Partner unit | $ | (0.76 | ) | $ | (0.50 | ) |
April 30, 2013 | |||
Current assets | $ | 113 | |
Property, plant and equipment, net | 1,608 | ||
Goodwill | 337 | ||
Other non-current assets | 1 | ||
Total Assets Acquired | $ | 2,059 | |
Less: | |||
Current liabilities | (93 | ) | |
Non-current liabilities | (36 | ) | |
Net Assets Acquired | $ | 1,930 |
Years Ended December 31, | |||||||
2013 (1) | 2012 | ||||||
Revenues: | |||||||
Partnership | $ | 2,253 | $ | 1,339 | |||
SUGS (1) | 268 | 661 | |||||
Combined | $ | 2,521 | $ | 2,000 | |||
Net income (loss): | |||||||
Partnership | $ | 63 | $ | 48 | |||
SUGS (1) | (36 | ) | (14 | ) | |||
Combined | $ | 27 | $ | 34 |
(1) | Combined amounts attributable to SUGS include the period from March 26, 2012 to December 31, 2012 for the year ended December 31, 2012, and the period from January 1, 2013 to April 30, 2013 for the year ended December 31, 2013. Subsequent to the closing of the SUGS Acquisition on April 30, 2013, the results of SUGS were attributable to the Partnership. |
December 31, | ||||||||||||
Ownership | Type | 2014 | 2013 | |||||||||
HPC | 49.99% | General Partner | $ | 422 | $ | 442 | ||||||
MEP | 50.00% | Membership Interest | 695 | 549 | ||||||||
Lone Star | 30.00% | Membership Interest | 1,162 | 1,070 | ||||||||
Ranch JV | 33.33% | Membership Interest | 38 | 36 | ||||||||
Aqua - PVR | 51.00% | Membership Interest | 46 | — | ||||||||
Mi Vida JV | 50.00% | Membership Interest | 54 | — | ||||||||
Others (1) | 1 | — | ||||||||||
$ | 2,418 | $ | 2,097 |
Year Ended December 31, 2014 | |||||||||||||||||||||||||||
HPC | MEP (2) | Lone Star | Ranch JV | Aqua - PVR | Mi Vida JV | Others (4) | |||||||||||||||||||||
Contributions to unconsolidated affiliates | $ | — | $ | 175 | $ | 114 | $ | — | $ | — | $ | 54 | $ | — | |||||||||||||
Distributions from unconsolidated affiliates | (48 | ) | (73 | ) | (137 | ) | (8 | ) | (1 | ) | — | (4 | ) | ||||||||||||||
Share of earnings of unconsolidated affiliates’ net income (loss) | 33 | 45 | 116 | 9 | (4 | ) | — | 2 | |||||||||||||||||||
Amortization of excess fair value of investment (1) | (6 | ) | — | — | — | — | — | — |
Year Ended December 31, 2013 | |||||||||||||||||||
HPC (3) | MEP | Lone Star | Ranch JV | Others (4) | |||||||||||||||
Contributions to unconsolidated affiliates | $ | — | $ | — | $ | 137 | $ | 2 | $ | — | |||||||||
Distributions from unconsolidated affiliates | (238 | ) | (72 | ) | (79 | ) | (2 | ) | — | ||||||||||
Share of earnings of unconsolidated affiliates’ net income | 36 | 40 | 64 | 1 | — | ||||||||||||||
Amortization of excess fair value of investment (1) | (6 | ) | — | — | — | — |
Year Ended December 31, 2012 | |||||||||||||||||||
HPC | MEP | Lone Star | Ranch JV | Others (4) | |||||||||||||||
Contributions to unconsolidated affiliates | $ | — | $ | — | $ | 343 | $ | 36 | $ | — | |||||||||
Distributions from unconsolidated affiliates | (61 | ) | (75 | ) | (68 | ) | — | — | |||||||||||
Share of earnings of unconsolidated affiliates’ net income (loss) | 35 | 42 | 44 | (1 | ) | (9 | ) | ||||||||||||
Amortization of excess fair value of investment (1) | (6 | ) | — | — | — | — |
(1) | The Partnership’s investment in HPC was adjusted to its fair value on May 26, 2010 and the excess fair value over net book value was comprised of two components: (1) $155 million was attributed to HPC’s long-lived assets and is being amortized as a reduction of income from unconsolidated affiliates over the useful lives of the respective assets, which vary from 15 to 30 years, and (2) $32 million could not be attributed to a specific asset and therefore will not be amortized in future periods. |
(2) | The Partnership contributed $175 million to MEP in September 2014 for the repayment of MEP’s debt. |
(3) | HPC entered into a $500 million 5-year revolving credit facility in September 2013, pursuant to which the Partnership pledged its 49.99% equity interest in HPC. Upon closing such credit facility, HPC borrowed $370 million to fund a non-recurring return of investment to its partners of which the Partnership received $185 million. The amount outstanding under this facility was $450 million as of December 31, 2014. The Partnership’s contingent obligation with respect to the outstanding borrowings under this facility was $225 million at December 31, 2014. |
(4) | Includes Coal Handling, Grey Ranch, and Sweeny JV. |
December 31, | |||||||
2014 | 2013 | ||||||
Current assets | $ | 16 | $ | 7 | |||
Property, plant and equipment, net | 95 | 100 | |||||
Other assets | 4 | 4 | |||||
Total assets | $ | 115 | $ | 111 | |||
Current liabilities | $ | 2 | $ | 3 | |||
Equity | 113 | 108 | |||||
Total liabilities and equity | $ | 115 | $ | 111 |
Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
Revenue | $ | 41 | $ | 16 | $ | 1 | |||||
Operating income (loss) | 29 | 4 | (2 | ) | |||||||
Net income (loss) | 29 | 4 | (2 | ) |
Assets | Liabilities | ||||||||||||||
December 31, | December 31, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
Derivatives not designated as cash flow hedges | |||||||||||||||
Current amounts | |||||||||||||||
Commodity contracts | $ | 75 | $ | 3 | $ | — | $ | 9 | |||||||
Long-term amounts | |||||||||||||||
Commodity contracts | 10 | 1 | — | — | |||||||||||
Embedded derivatives in Series A Preferred Units | — | — | 16 | 19 | |||||||||||
Total derivatives | $ | 85 | $ | 4 | $ | 16 | $ | 28 |
Years Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Derivatives in cash flow hedging relationships: | Change in Value Recognized in AOCI on Derivatives (Effective Portion) | ||||||||||||
Commodity derivatives | $ | — | $ | — | $ | (4 | ) | ||||||
Derivatives in cash flow hedging relationships: | Location of Gain/(Loss) Recognized in Income | Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | |||||||||||
Commodity derivatives | Revenue | $ | — | $ | — | $ | 6 |
Years Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Derivatives not designated in a hedging relationship: | Location of Gain/(Loss) Recognized in Income | Amount of Gain/(Loss) from De-designation Amortized from AOCI into Income | |||||||||||
Commodity derivatives | Revenue | $ | — | $ | — | $ | (5 | ) | |||||
Derivatives not designated in a hedging relationship: | Location of Gain/(Loss) Recognized in Income | Amount of Gain/(Loss) Recognized in Income from Derivatives | |||||||||||
Commodity derivatives | Revenue | $ | 93 | $ | (9 | ) | $ | 16 | |||||
Embedded derivatives | Other income & deductions | 3 | 6 | 14 | |||||||||
$ | 96 | $ | (3 | ) | $ | 30 |
December 31, | |||||||
2014 | 2013 | ||||||
Senior notes | $ | 5,089 | $ | 2,800 | |||
Revolving loans | 1,504 | 510 | |||||
Unamortized premiums and discounts | 48 | — | |||||
Long-term debt | $ | 6,641 | $ | 3,310 | |||
Availability under revolving credit facility: | |||||||
Total credit facility limit | $ | 2,000 | $ | 1,200 | |||
Revolving loans | (1,504 | ) | (510 | ) | |||
Letters of credit | (23 | ) | (14 | ) | |||
Total available | $ | 473 | $ | 676 |
Year Ended December 31, | Amount | ||
2015 | $ | — | |
2016 | — | ||
2017 | — | ||
2018 | — | ||
2019 | 2,003 | ||
Thereafter | 4,590 | ||
Total * | $ | 6,593 |
* | Excludes a $67 million unamortized premium on the 2020 PVR Notes and the 2021 PVR Notes assumed by the Partnership and a $19 million unamortized discount on the combined 2022 Notes. |
• | the addition of provisions permitting investments in Mi Vida JV affording it similar treatment to the Partnership’s existing joint ventures; |
• | an increase in certain permitted covenant baskets; and |
• | updates to various pricing terms and the permitted maximum total leverage ratio to reflect the Partnership’s growth. |
• | A 75 bps decrease in pricing, with an additional 50 bps decrease upon the achievement of an investment grade rating; |
• | No limitation on the maximum amount that the loan parties may invest in joint ventures existing on the date of the credit agreement so long as the Partnership is in pro forma compliance with the financial covenants; |
• | The addition of a “Restricted Subsidiary” structure such that certain designated subsidiaries are not subject to the credit facility covenants and do not guarantee the obligations thereunder or pledge their assets in support thereof; |
• | The addition of provisions such that upon the achievement of an investment grade rating by the Partnership, the collateral package will be released; the facility will become unsecured; and the covenant package will be significantly reduced; |
• | An eight-quarter increase in the permitted Total Leverage Ratio; and |
• | After March 2015, an increase in the permitted total leverage ratio for the two fiscal quarters following any $50 million or greater acquisition. |
• | incur indebtedness; |
• | grant liens; |
• | enter into sale and leaseback transactions; |
• | make certain investments, loans and advances; |
• | dissolve or enter into a merger or consolidation; |
• | enter into asset sales or make acquisitions; |
• | enter into transactions with affiliates; |
• | prepay other indebtedness or amend organizational documents or transactions documents (as defined in the New Credit Agreement); |
• | issue capital stock or create subsidiaries; or |
• | engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the New Credit Agreement or reasonable extension thereof. |
• | $400 million in aggregate principal amount of our 5.75% senior notes due September 1, 2020 (the “2020 Notes“) with interest payable semi-annually in arrears on March 1 and September 1; |
• | $500 million in aggregate principal amount of our 6.5% senior notes due July 15, 2021 (the “2021 Notes“) with interest payable semi-annually in arrears on January 15 and July 15; |
• | $900 million in aggregate principal of our 5.875% senior notes due March 1, 2022 (the “2022 Notes“), issued in February 2014, with interest payable semi-annually in arrears on March 1 and September 1; |
• | $700 million in aggregate principal amount of our 5.5% senior notes due April 15, 2023 (the “2023 5.5% Notes“) with interest payable semi-annually in arrears on April 15 and October 15; |
• | $600 million in aggregate principal amount of our 4.5% senior notes due November 1, 2023 (the “2023 4.5% Notes“) with interest payable semi-annually in arrears on May 1 and November 1; |
• | $390 million, after partial redemption, in aggregate principal amount of our 8.375% senior notes due June 1, 2020 (the “2020 PVR Notes“) with interest payable semi-annually in arrears on June 1 and December 1; |
• | $400 million in aggregate principal amount of our 6.5% senior notes due May 15, 2021 (the “2021 PVR Notes“) with interest payable semi-annually in arrears on May 15 and November 15; |
• | $499 million in aggregate principal amount of our 8.375% senior notes due June 1, 2019 (the “2019 Notes“) with interest payable semi-annually in arrears on June 1 and December 1; and |
• | $700 million in aggregate principal amount of our 5% senior notes due October 1, 2022 (the “October 2022 Notes“) with interest payable semi-annually in arrears on April 1 and October 1. |
• | 2020 Notes - Redeemable, in whole or in part, prior to June 1, 2020 at 100% of the principal amount plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date; redeemable, in whole or in part, on or after June 1, 2020 at 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date |
• | 2021 Notes - Any time prior to July 15, 2014, up to 35% may be redeemed at a price of 106.5% plus accrued and unpaid interest, if any; beginning July 15, 2016, 100% may be redeemed at fixed redemption price of 103.25% (July 15, 2017 - 102.167%, July 15, 2018 - 101.083% and July 15, 2019 and thereafter - 100%) plus accrued and unpaid interest, if any, to the redemption date |
• | 2022 Notes - Redeemable, in whole or in part, prior to December 1, 2021 at 100% at the principal amount plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date; redeemable, in whole or in part, on or after December 1, 2021 at 100% at the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date |
• | 2023 5.5% Notes - Any time prior to October 15, 2015, up to 35% may be redeemed at a price of 105.5% plus accrued and unpaid interest, if any; beginning October 15, 2017, 100% may be redeemed at fixed redemption price of 102.75% (October 15, 2018 - 101.833%, October 15, 2019 - 100.917% and October 15, 2020 and thereafter - 100%) plus accrued and unpaid interest, if any, to the redemption date |
• | 2023 4.5% Notes - Redeemable, in whole or in part, prior to August 1, 2023 at 100% of the principal amount plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date; redeemable, in whole or in part, on or after August 1, 2023 at 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date |
• | 2020 PVR Notes - Any time prior to June 1, 2015, up to 35% may be redeemed at a price of 108.375% plus accrued and unpaid interest, if any; beginning June 1, 2016, 100% may be redeemed at fixed redemption price of 104.188% (June 1, 2017 - 102.094%, June 1, 2018 and thereafter - 100%) plus accrued and unpaid interest, if any, to the redemption date |
• | 2021 PVR Notes - Any time prior to May 15, 2016, up to 35% may be redeemed at a price of 106.5% plus accrued and unpaid interest and liquidated damages, if any; beginning May 15, 2016, 100% may be redeemed at a fixed redemption price of 104.875% (May 15, 2017 - 103.250%, May 15, 2018 - 101.625% and May 15, 2019 and thereafter - 100%) plus accrued and unpaid interest, if any, to the redemption date |
• | 2019 Notes - Redeemable, in whole or in part, prior to June 1, 2015 at 100% at the principal amount plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date; beginning June 1, 2015, 100% may be redeemed at a fixed redemption price of 104.188% (June 1, 2016 - 102.094% and June 1, 2017 and thereafter - 100%) plus accrued and unpaid interest, if any, to the redemption date |
• | October 2022 Notes - Redeemable, in whole or in part, prior to July 1, 2022 at 100% of the principal amount plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date; redeemable, in whole or in part, on or |
• | incur additional indebtedness; |
• | pay distributions on, or repurchase or redeem our equity interests; |
• | make certain investments; |
• | incur liens; |
• | enter into certain types of transactions with affiliates; and |
• | sell assets or consolidate or merge with or into other companies. |
Customer Relations | Trade Names | Total | |||||||||
Balance at January 1, 2013 | $ | 655 | $ | 57 | $ | 712 | |||||
Amortization | (26 | ) | (4 | ) | (30 | ) | |||||
Balance at December 31, 2013 | 629 | 53 | 682 | ||||||||
Amortization | (105 | ) | (3 | ) | (108 | ) | |||||
Intangible assets acquired | 2,865 | — | 2,865 | ||||||||
Balance at December 31, 2014 | $ | 3,389 | $ | 50 | $ | 3,439 |
• | Level 1—unadjusted quoted prices for identical assets or liabilities in active accessible markets; |
• | Level 2—inputs that are observable in the marketplace other than those classified as Level 1; and |
• | Level 3—inputs that are unobservable in the marketplace and significant to the valuation. |
Fair Value Measurement at December 31, | |||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||
Fair Value Total | Level 2 | Level 3 | Fair Value Total | Level 2 | Level 3 | ||||||||||||||||||
Assets | |||||||||||||||||||||||
Commodity Derivatives: | |||||||||||||||||||||||
Natural Gas | $ | 26 | $ | 26 | $ | — | $ | 2 | $ | 2 | $ | — | |||||||||||
Natural Gas Liquids | 23 | 23 | — | 2 | 2 | — | |||||||||||||||||
Condensate | 36 | 36 | — | — | — | — | |||||||||||||||||
Total Assets | $ | 85 | $ | 85 | $ | — | $ | 4 | $ | 4 | $ | — | |||||||||||
Liabilities | |||||||||||||||||||||||
Commodity Derivatives: | |||||||||||||||||||||||
Natural Gas | $ | — | $ | — | $ | — | $ | 4 | $ | 4 | $ | — | |||||||||||
Natural Gas Liquids | — | — | — | 4 | 4 | — | |||||||||||||||||
Condensate | — | — | — | 1 | 1 | — | |||||||||||||||||
Embedded Derivatives in Series A Preferred Units | 16 | — | 16 | 19 | — | 19 | |||||||||||||||||
Total Liabilities | $ | 16 | $ | — | $ | 16 | $ | 28 | $ | 9 | $ | 19 |
Unobservable Input | December 31, 2014 | ||
Credit Spread | 4.76 | % | |
Volatility | 35.8 | % |
Embedded Derivatives in Series A Preferred Units | |||
Balance at January 1, 2013 | $ | 25 | |
Change in fair value, net of gain at conversion of $26 million | (6 | ) | |
Balance at December 31, 2013 | 19 | ||
Change in fair value | (3 | ) | |
Balance at December 31, 2014 | $ | 16 |
For the year ending December 31, | Operating Lease | |||
2015 | $ | 5 | ||
2016 | 5 | |||
2017 | 4 | |||
2018 | 3 | |||
2019 | 2 | |||
Thereafter | 26 | |||
Total minimum lease payments | $ | 45 |
December 31, | |||||||
2014 | 2013 | ||||||
Current | $ | 2 | $ | 2 | |||
Noncurrent | 8 | 6 | |||||
Total environmental liabilities | $ | 10 | $ | 8 |
Units | Amount | ||||||
Balance at January 1, 2013 | 4,371,586 | $ | 73 | ||||
Series A Preferred Units converted to common units | (2,459,017 | ) | (41 | ) | |||
Balance at January 1, 2014 | 1,912,569 | 32 | |||||
Accretion to redemption value | N/A | 1 | |||||
Balance at December 31, 2014 | 1,912,569 | $ | 33 | * |
December 31, | |||||||
2014 | 2013 | ||||||
Related party receivables | |||||||
ETE and its subsidiaries | 43 | 25 | |||||
HPC | 1 | 1 | |||||
Ranch JV | 1 | 2 | |||||
Total related party receivables | $ | 45 | $ | 28 | |||
Related party payables | |||||||
ETE and its subsidiaries | 50 | 68 | |||||
HPC | 3 | 1 | |||||
Mi Vida JV | 11 | — | |||||
Total related party payables | $ | 64 | $ | 69 |
Years Ended December 31, | |||||||||||||
Reportable Segment | 2014 | 2013 | 2012 | ||||||||||
Customer | |||||||||||||
Customer A | Gathering and Processing | $ | — | $ | 381 | $ | 367 | ||||||
Customer B | Gathering and Processing | 780 | 362 | 451 | |||||||||
Supplier | |||||||||||||
Supplier A | Gathering and Processing | — | 164 | 171 | |||||||||
Supplier B | Gathering and Processing | — | 185 | — |
• | Gathering and Processing. The Partnership provides “wellhead-to-market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs from the raw natural gas and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems, the gathering of oil (crude and/or condensate, a lighter oil) received from producers, the gathering and disposing of salt water, and natural gas and NGL marketing and trading. This segment also includes the Partnership’s 60% membership interest in ELG, which operates natural gas gathering, oil pipeline, and oil stabilization facilities in south Texas, the Partnership’s 33.33% membership interest in Ranch JV, which processes natural gas delivered from NGL-rich shale formations in west Texas, the Partnership’s 50% interest in Sweeny JV, which operates a natural gas gathering facility in south Texas, the Partnership’s 51% membership interest in Aqua - PVR, which transports and supplies fresh water to natural gas producers in the Marcellus shale in Pennsylvania, the Partnership’s 75% membership interest in ORS, which will operate a natural gas gathering system in the Utica shale in Ohio, and the Partnership’s 50% interest in Mi Vida JV, which will operate a cryogenic processing plant and related facilities in west Texas. |
• | Natural Gas Transportation. The Partnership owns a 49.99% general partner interest in HPC, which owns RIGS, a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets, and a 50% membership interest in MEP, which owns a 500-mile interstate natural gas pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipe Line system in Butler, Alabama. This segment also includes Gulf States, which owns a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana. |
• | NGL Services. The Partnership owns a 30% membership interest in Lone Star, an entity owning a diverse set of midstream energy assets including NGL pipelines, storage, fractionation and processing facilities located in Texas, New Mexico, Mississippi and Louisiana. |
• | Contract Services. The Partnership owns and operates a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. The Partnership also owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management. |
• | Natural Resources. The Partnership is involved in the management of coal and natural resources properties and the related collection of royalties. The Partnership also earns revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. This segment also included the Partnership’s 50% interest in Coal Handling, which owns and operates end-user coal handling facilities. The Partnership purchased the remaining 50% interest in these companies effective December 31, 2014. |
• | Corporate. The Corporate segment comprises the Partnership’s corporate assets. |
Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
External Revenue | |||||||||||
Gathering and Processing | $ | 4,570 | $ | 2,287 | $ | 1,797 | |||||
Natural Gas Transportation | — | 1 | 1 | ||||||||
NGL Services | — | — | — | ||||||||
Contract Services | 307 | 215 | 183 | ||||||||
Natural Resources | 58 | — | — | ||||||||
Corporate | 16 | 18 | 19 | ||||||||
Eliminations | — | — | — | ||||||||
Total | $ | 4,951 | $ | 2,521 | $ | 2,000 | |||||
Intersegment Revenue | |||||||||||
Gathering and Processing | $ | — | $ | — | $ | — | |||||
Natural Gas Transportation | — | — | — | ||||||||
NGL Services | — | — | — | ||||||||
Contract Services | 14 | 15 | 21 | ||||||||
Natural Resources | — | — | — | ||||||||
Corporate | — | — | — | ||||||||
Eliminations | (14 | ) | (15 | ) | (21 | ) | |||||
Total | $ | — | $ | — | $ | — | |||||
Cost of Sales | |||||||||||
Gathering and Processing | $ | 3,381 | $ | 1,767 | $ | 1,373 | |||||
Natural Gas Transportation | — | — | (1 | ) | |||||||
NGL Services | — | — | — | ||||||||
Contract Services | 67 | 26 | 15 | ||||||||
Natural Resources | — | — | — | ||||||||
Corporate | 4 | — | — | ||||||||
Eliminations | — | — | — | ||||||||
Total | $ | 3,452 | $ | 1,793 | $ | 1,387 | |||||
Segment Margin | |||||||||||
Gathering and Processing | $ | 1,189 | $ | 520 | $ | 423 | |||||
Natural Gas Transportation | — | 1 | 2 | ||||||||
NGL Services | — | — | — | ||||||||
Contract Services | 254 | 204 | 189 | ||||||||
Natural Resources | 58 | — | — | ||||||||
Corporate | 12 | 18 | 20 | ||||||||
Eliminations | (14 | ) | (15 | ) | (21 | ) | |||||
Total | $ | 1,499 | $ | 728 | $ | 613 | |||||
Years Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
Operation and Maintenance | |||||||||||
Gathering and Processing | $ | 360 | $ | 237 | $ | 183 | |||||
Natural Gas Transportation | — | — | — | ||||||||
NGL Services | — | — | — | ||||||||
Contract Services | 86 | 72 | 66 | ||||||||
Natural Resources | 12 | — | — | ||||||||
Corporate | 3 | 1 | — | ||||||||
Eliminations | (13 | ) | (14 | ) | (21 | ) | |||||
Total | $ | 448 | $ | 296 | $ | 228 | |||||
Depreciation, Depletion and Amortization | |||||||||||
Gathering and Processing | $ | 385 | $ | 186 | $ | 159 | |||||
Natural Gas Transportation | — | — | — | ||||||||
NGL Services | — | — | — | ||||||||
Contract Services | 134 | 98 | 86 | ||||||||
Natural Resources | 14 | — | — | ||||||||
Corporate | 8 | 3 | 7 | ||||||||
Eliminations | — | — | — | ||||||||
Total | $ | 541 | $ | 287 | $ | 252 |
Income from Unconsolidated Affiliates | |||||||||||
Gathering and Processing | $ | 5 | $ | 1 | $ | (10 | ) | ||||
Natural Gas Transportation | 72 | 70 | 71 | ||||||||
NGL Services | 116 | 64 | 44 | ||||||||
Contract Services | — | — | — | ||||||||
Natural Resources | 2 | — | — | ||||||||
Corporate | — | — | — | ||||||||
Eliminations | — | — | — | ||||||||
Total | $ | 195 | $ | 135 | $ | 105 | |||||
Expenditures for Long-Lived Assets | |||||||||||
Gathering and Processing | $ | 700 | $ | 721 | $ | 395 | |||||
Natural Gas Transportation | — | — | — | ||||||||
NGL Services | — | — | — | ||||||||
Contract Services | 371 | 311 | 164 | ||||||||
Natural Resources | — | — | — | ||||||||
Corporate | 17 | 2 | 1 | ||||||||
Eliminations | — | — | — | ||||||||
Total | $ | 1,088 | $ | 1,034 | $ | 560 |
December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
Assets | |||||||||||
Gathering and Processing | $ | 12,069 | $ | 4,748 | $ | 4,210 | |||||
Natural Gas Transportation | 1,119 | 991 | 1,232 | ||||||||
NGL Services | 1,162 | 1,070 | 948 | ||||||||
Contract Services | 2,035 | 1,897 | 1,672 | ||||||||
Natural Resources | 529 | — | — | ||||||||
Corporate | 189 | 76 | 61 | ||||||||
Eliminations | — | — | — | ||||||||
Total | $ | 17,103 | $ | 8,782 | $ | 8,123 | |||||
Investments in Unconsolidated Affiliates | |||||||||||
Gathering and Processing | $ | 139 | $ | 36 | $ | 35 | |||||
Natural Gas Transportation | 1,117 | 991 | 1,231 | ||||||||
NGL Services | 1,162 | 1,070 | 948 | ||||||||
Contract Services | — | — | — | ||||||||
Natural Resources | — | — | — | ||||||||
Corporate | — | — | — | ||||||||
Eliminations | — | — | — | ||||||||
Total | $ | 2,418 | $ | 2,097 | $ | 2,214 | |||||
Goodwill | |||||||||||
Gathering and Processing (1) | $ | 732 | $ | 651 | $ | 651 | |||||
Natural Gas Transportation | — | — | — | ||||||||
NGL Services | — | — | — | ||||||||
Contract Services | 476 | 477 | 477 | ||||||||
Natural Resources | 15 | — | — | ||||||||
Corporate | — | — | — | ||||||||
Eliminations | — | — | — | ||||||||
Total | $ | 1,223 | $ | 1,128 | $ | 1,128 |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Total segment margin | $ | 1,499 | $ | 728 | $ | 613 | ||||||
Operation and maintenance | (448 | ) | (296 | ) | (228 | ) | ||||||
General and administrative | (158 | ) | (88 | ) | (100 | ) | ||||||
Gain (loss) on assets sales, net | 1 | (2 | ) | (3 | ) | |||||||
Depreciation, depletion and amortization | (541 | ) | (287 | ) | (252 | ) | ||||||
Goodwill impairment | (370 | ) | — | — | ||||||||
Income from unconsolidated affiliates | 195 | 135 | 105 | |||||||||
Interest expense, net | (304 | ) | (164 | ) | (122 | ) | ||||||
Loss on debt refinancing, net | (25 | ) | (7 | ) | (8 | ) | ||||||
Other income and deductions, net | 12 | 7 | 29 | * | ||||||||
(Loss) income before income taxes | $ | (139 | ) | $ | 26 | $ | 34 |
* | Other income and deductions, net for the year ended December 31, 2012, included a one-time producer payment of $16 million related to an assignment of certain contracts. |
Common Unit Options | Units | Weighted Average Exercise Price | |||||
Outstanding at the beginning of period | 142,550 | $ | 22.04 | ||||
Exercised | (34,900 | ) | 20.03 | ||||
Outstanding at end of period | 107,650 | 22.68 | |||||
Exercisable at the end of the period | 107,650 |
Phantom Units | Units | Weighted Average Grant Date Fair Value | |||||
Outstanding at the beginning of the period | 982,242 | $ | 23.16 | ||||
Service condition grants | 1,450,230 | 25.24 | |||||
Vested service condition | (183,380 | ) | 25.25 | ||||
Forfeited service condition | (81,373 | ) | 24.83 | ||||
Total outstanding at end of period | 2,167,719 | 24.31 |
Cash Restricted Units | Units | ||
Outstanding at the beginning of the period | — | ||
Service condition grants | 400,928 | ||
Vested service condition | (500 | ) | |
Forfeited service condition | (21,100 | ) | |
Total outstanding at end of period | 379,328 |
December 31, 2014 | |||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated Partnership | |||||||||||||||
ASSETS | |||||||||||||||||||
Cash | $ | — | $ | — | $ | 32 | $ | (8 | ) | $ | 24 | ||||||||
All other current assets | — | 667 | 13 | (1 | ) | 679 | |||||||||||||
Property, plant, and equipment, net | — | 8,948 | 353 | (84 | ) | 9,217 | |||||||||||||
Investments in subsidiaries | 19,829 | — | — | (19,829 | ) | — | |||||||||||||
Investments in unconsolidated affiliates | — | 2,252 | — | 166 | 2,418 | ||||||||||||||
All other assets | — | 4,765 | — | — | 4,765 | ||||||||||||||
TOTAL ASSETS | $ | 19,829 | $ | 16,632 | $ | 398 | $ | (19,756 | ) | $ | 17,103 | ||||||||
LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST | |||||||||||||||||||
All other current liabilities | — | 723 | 34 | (1 | ) | 756 | |||||||||||||
Long-term liabilities | 5,185 | 1,575 | 6 | (4 | ) | 6,762 | |||||||||||||
Noncontrolling interest | — | — | — | 120 | 120 | ||||||||||||||
Total partners’ capital and noncontrolling interest | 14,644 | 14,334 | 358 | (19,871 | ) | 9,465 | |||||||||||||
TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST | $ | 19,829 | $ | 16,632 | $ | 398 | $ | (19,756 | ) | $ | 17,103 |
December 31, 2013 | |||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated Partnership | |||||||||||||||
ASSETS | |||||||||||||||||||
Cash | $ | — | $ | — | $ | 19 | $ | — | $ | 19 | |||||||||
All other current assets | — | 366 | 15 | — | 381 | ||||||||||||||
Property, plant, and equipment, net | — | 4,244 | 174 | — | 4,418 | ||||||||||||||
Investments in subsidiaries | 10,446 | — | — | (10,446 | ) | — | |||||||||||||
Investments in unconsolidated affiliates | — | 1,995 | — | 102 | 2,097 | ||||||||||||||
All other assets | — | 1,867 | — | — | 1,867 | ||||||||||||||
TOTAL ASSETS | $ | 10,446 | $ | 8,472 | $ | 208 | $ | (10,344 | ) | $ | 8,782 | ||||||||
LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST | |||||||||||||||||||
All other current liabilities | — | 466 | 9 | — | 475 | ||||||||||||||
Long-term liabilities | 2,832 | 559 | — | — | 3,391 | ||||||||||||||
Noncontrolling interest | — | — | — | 102 | 102 | ||||||||||||||
Total partners’ capital and noncontrolling interest | 7,614 | 7,447 | 199 | (10,446 | ) | 4,814 | |||||||||||||
TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST | $ | 10,446 | $ | 8,472 | $ | 208 | $ | (10,344 | ) | $ | 8,782 |
For the year ended December 31, 2014 | |||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated Partnership | |||||||||||||||
Revenues | $ | — | $ | 4,888 | $ | 66 | $ | (3 | ) | $ | 4,951 | ||||||||
Operating costs, expenses, and other | — | 4,942 | 35 | (9 | ) | 4,968 | |||||||||||||
Operating (loss) income | — | (54 | ) | 31 | 6 | (17 | ) | ||||||||||||
Income from unconsolidated affiliates | — | 195 | — | — | 195 | ||||||||||||||
Interest expense, net | (290 | ) | (14 | ) | — | — | (304 | ) | |||||||||||
Loss on debt refinancing, net | (24 | ) | (1 | ) | — | — | (25 | ) | |||||||||||
Equity in consolidated subsidiaries | 166 | — | — | (166 | ) | — | |||||||||||||
Other income and deductions, net | 3 | 9 | — | — | 12 | ||||||||||||||
(Loss) income before income taxes | (145 | ) | 135 | 31 | (160 | ) | (139 | ) | |||||||||||
Income tax expense (benefit) | 4 | (2 | ) | 1 | — | 3 | |||||||||||||
Net (loss) income | (149 | ) | 137 | 30 | (160 | ) | (142 | ) | |||||||||||
Net income attributable to noncontrolling interest | — | — | — | (15 | ) | (15 | ) | ||||||||||||
Net (loss) income attributable to Regency Energy Partners LP | $ | (149 | ) | $ | 137 | $ | 30 | $ | (175 | ) | $ | (157 | ) | ||||||
Total other comprehensive income | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||
Comprehensive (loss) income | (149 | ) | 137 | 30 | (160 | ) | (142 | ) | |||||||||||
Comprehensive income attributable to noncontrolling interest | — | — | — | 15 | 15 | ||||||||||||||
Comprehensive (loss) income attributable to Regency Energy Partners LP | $ | (149 | ) | $ | 137 | $ | 30 | $ | (175 | ) | $ | (157 | ) |
For the year ended December 31, 2013 | |||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated Partnership | |||||||||||||||
Revenues | $ | — | $ | 2,489 | $ | 32 | $ | — | $ | 2,521 | |||||||||
Operating costs, expenses, and other | 3 | 2,448 | 15 | — | 2,466 | ||||||||||||||
Operating (loss) income | (3 | ) | 41 | 17 | — | 55 | |||||||||||||
Income from unconsolidated affiliates | — | 135 | — | — | 135 | ||||||||||||||
Interest expense, net | (148 | ) | (16 | ) | — | — | (164 | ) | |||||||||||
Loss on debt refinancing, net | (7 | ) | — | — | — | (7 | ) | ||||||||||||
Equity in consolidated subsidiaries | 172 | — | — | (172 | ) | — | |||||||||||||
Other income and deductions, net | 7 | — | — | — | 7 | ||||||||||||||
Income before income taxes | 21 | 160 | 17 | (172 | ) | 26 | |||||||||||||
Income tax expense (benefit) | 1 | (2 | ) | — | — | (1 | ) | ||||||||||||
Net income | 20 | 162 | 17 | (172 | ) | 27 | |||||||||||||
Net income attributable to noncontrolling interest | — | (8 | ) | — | — | (8 | ) | ||||||||||||
Net income attributable to Regency Energy Partners LP | $ | 20 | $ | 154 | $ | 17 | $ | (172 | ) | $ | 19 | ||||||||
Total other comprehensive income | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||
Comprehensive income | 20 | 162 | 17 | (172 | ) | 27 | |||||||||||||
Comprehensive income attributable to noncontrolling interest | — | 8 | — | — | 8 | ||||||||||||||
Comprehensive income attributable to Regency Energy Partners LP | $ | 20 | $ | 154 | $ | 17 | $ | (172 | ) | $ | 19 |
For the year ended December 31, 2012 | |||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated Partnership | |||||||||||||||
Revenues | $ | — | $ | 1,985 | $ | 15 | $ | — | $ | 2,000 | |||||||||
Operating costs, expenses, and other | 10 | 1,951 | 9 | — | 1,970 | ||||||||||||||
Operating (loss) income | (10 | ) | 34 | 6 | — | 30 | |||||||||||||
Income from unconsolidated affiliates | — | 105 | — | — | 105 | ||||||||||||||
Interest expense, net | (104 | ) | (18 | ) | — | — | (122 | ) | |||||||||||
Gain (loss) on debt refinancing, net | (8 | ) | — | — | — | (8 | ) | ||||||||||||
Equity in consolidated subsidiaries | 141 | — | — | (141 | ) | — | |||||||||||||
Other income and deductions, net | 14 | 15 | — | — | 29 | ||||||||||||||
Income before income taxes | 33 | 136 | 6 | (141 | ) | 34 | |||||||||||||
Income tax expense (benefit) | 1 | (1 | ) | — | — | — | |||||||||||||
Net income | 32 | 137 | 6 | (141 | ) | 34 | |||||||||||||
Net income attributable to noncontrolling interest | — | (2 | ) | — | — | (2 | ) | ||||||||||||
Net income attributable to Regency Energy Partners LP | $ | 32 | $ | 135 | $ | 6 | $ | (141 | ) | $ | 32 | ||||||||
Total other comprehensive income (loss) | $ | — | $ | 2 | $ | — | $ | — | $ | 2 | |||||||||
Comprehensive income | 32 | 139 | 6 | (141 | ) | 36 | |||||||||||||
Comprehensive income attributable to noncontrolling interest | — | 2 | — | — | 2 | ||||||||||||||
Comprehensive income attributable to Regency Energy Partners LP | $ | 32 | $ | 137 | $ | 6 | $ | (141 | ) | $ | 34 |
For the year ended December 31, 2014 | |||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated Partnership | |||||||||||||||
Cash flows from operating activities | $ | — | $ | 664 | $ | 56 | $ | (1 | ) | $ | 719 | ||||||||
Cash flows from investing activities | — | (2,130 | ) | (30 | ) | (9 | ) | (2,169 | ) | ||||||||||
Cash flows from financing activities | — | 1,466 | (13 | ) | 2 | 1,455 | |||||||||||||
Change in cash | — | — | 13 | (8 | ) | 5 | |||||||||||||
Cash at beginning of period | — | — | 19 | — | 19 | ||||||||||||||
Cash at end of period | $ | — | $ | — | $ | 32 | $ | (8 | ) | $ | 24 |
For the year ended December 31, 2013 | |||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated Partnership | |||||||||||||||
Cash flows from operating activities | $ | — | $ | 424 | $ | 12 | $ | — | $ | 436 | |||||||||
Cash flows from investing activities | — | (1,303 | ) | (90 | ) | — | (1,393 | ) | |||||||||||
Cash flows from financing activities | — | 879 | 44 | — | 923 | ||||||||||||||
Change in cash | — | — | (34 | ) | — | (34 | ) | ||||||||||||
Cash at beginning of period | — | — | 53 | — | 53 | ||||||||||||||
Cash at end of period | $ | — | $ | — | $ | 19 | $ | — | $ | 19 |
For the year ended December 31, 2012 | |||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated Partnership | |||||||||||||||
Cash flows from operating activities | $ | — | $ | 316 | $ | 8 | $ | — | $ | 324 | |||||||||
Cash flows from investing activities | — | (746 | ) | (61 | ) | — | (807 | ) | |||||||||||
Cash flows from financing activities | — | 430 | 105 | — | 535 | ||||||||||||||
Change in cash | — | — | 52 | — | 52 | ||||||||||||||
Cash at beginning of period | — | — | 1 | — | 1 | ||||||||||||||
Cash at end of period | $ | — | $ | — | $ | 53 | $ | — | $ | 53 |
Quarter Ended | ||||||||||||||||
2014 | December 31 | September 30 | June 30 | March 31 | ||||||||||||
Operating revenues | $ | 1,427 | $ | 1,483 | $ | 1,178 | $ | 863 | ||||||||
Operating (loss) income | (218 | ) | 144 | 35 | 22 | |||||||||||
Net (loss) income attributable to Regency Energy Partners LP | (261 | ) | 103 | (8 | ) | 9 | ||||||||||
Earnings per common units: | ||||||||||||||||
Basic net (loss) income per common unit | (0.67 | ) | 0.23 | (0.05 | ) | 0.00 | ||||||||||
Diluted net (loss) income per common unit | (0.67 | ) | 0.23 | (0.05 | ) | 0.00 | ||||||||||
Quarter Ended | ||||||||||||||||
2013 | December 31 | September 30 | June 30 | March 31 | ||||||||||||
Operating revenues | $ | 677 | $ | 665 | $ | 639 | $ | 540 | ||||||||
Operating income (loss) | 12 | 24 | 34 | (15 | ) | |||||||||||
Net (loss) income attributable to Regency Energy Partners LP | (1 | ) | 39 | 10 | (29 | ) | ||||||||||
Earnings per common units: | ||||||||||||||||
Basic net (loss) income per common unit | (0.03 | ) | 0.16 | 0.07 | (0.06 | ) | ||||||||||
Diluted net (loss) income per common unit | (0.03 | ) | 0.05 | 0.07 | (0.06 | ) |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Summary of Significant Accounting Policies - Inventory (Details) (USD $)
In Millions, unless otherwise specified |
Dec. 31, 2014
MMbtu
|
Dec. 31, 2013
MMbtu
|
||||
---|---|---|---|---|---|---|
Natural Gas Volumes | 34,311,000 | 42,843,000 | ||||
Natural Gas Inventory | $ 105 | [1] | $ 184 | [1] | ||
Inventory, Raw Materials and Supplies | 14 | 19 | ||||
Inventories | 119 | 203 | ||||
Energy Related Inventory | $ 119 | $ 203 | ||||
|
RELATED PARTY TRANSACTIONS Related Party Distributions (Details) (USD $)
In Millions, unless otherwise specified |
9 Months Ended | 12 Months Ended | 3 Months Ended | |
---|---|---|---|---|
Dec. 31, 2012
|
Dec. 31, 2014
|
Dec. 31, 2013
|
Mar. 25, 2012
|
|
Successor | ||||
Distributions from unconsolidated affiliates | $ 1 | $ 6 | $ 15 | |
Successor | ETP [Member] | ||||
Distributions from unconsolidated affiliates | 6 | 9 | 8 | |
Successor | Regency [Member] | ||||
Distributions from unconsolidated affiliates | 0 | 61 | 44 | |
Predecessor | ||||
Distributions from unconsolidated affiliates | 0 | |||
Predecessor | ETP [Member] | ||||
Distributions from unconsolidated affiliates | 0 | |||
Predecessor | Regency [Member] | ||||
Distributions from unconsolidated affiliates | $ 0 |
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