Energy Transfer Equity : Regency Energy Partners Reports Full-Year 2014 Results

Regency Energy Partners LP (NYSE:RGP), (“Regency” or the “Partnership”), announced today its financial results for the fourth-quarter and full-year ended December 31, 2014.

For full-year 2014, adjusted EBITDA increased 93 percent to $1.2 billion, compared to $608 million in 2013, primarily due to contributions from the midstream assets Regency acquired in 2014 from PVR Partners, L.P. (“PVR”), Hoover Energy Partners, LP (“Hoover”) and Eagle Rock Energy Partners, L.P. (“Eagle Rock”), volume growth in the gathering and processing segment, volume growth at the Lone Star Joint Venture, as well as an increase in revenue generating horsepower in the contract services segment.

For the year-ended December 31, 2014, Regency generated $786 million in distributable cash flow (“DCF”), compared to $411 million for full-year 2013.

For the year ended December 31, 2014, Regency reported a net loss of $157 million, compared to net income of $19 million for the year ended December 31, 2013. Increases in segment margin and investment in unconsolidated affiliates were offset by a goodwill impairment charge related to the Permian region within the gathering and processing segment, as well as increases in depreciation, depletion, and amortization, operation and maintenance expenses, interest expense, and general and administrative expenses as a result of the Hoover, PVR and Eagle Rock midstream acquisitions.

REVIEW OF SEGMENT PERFORMANCE

Adjusted total segment margin increased to $1.4 billion for full-year 2014, compared to $729 million full-year 2013.

Gathering and Processing - Regency 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 our 60% membership interest in ELG, which operates natural gas gathering, oil pipeline, and oil stabilization facilities in south Texas, a 33.33% membership interest in Ranch JV, which processes natural gas delivered from NGL - rich shale formations in west Texas, our 50% partnership interest in Sweeny JV, which operates a natural gas gathering facility in south Texas, our 51% membership interest in Aqua - PVR, which transports and supplies fresh water to natural gas producers in the Marcellus shale in Pennsylvania, our 75% membership interest in ORS, which will operate a natural gas gathering system in the Utica Shale in Ohio, and our 50% interest in Mi Vida JV, which will operate a cryogenic processing plant and related facilities in West Texas.

Adjusted segment margin for the Gathering and Processing segment, which excludes non-cash gains and losses from commodity derivatives, was $1.1 billion for full-year 2014, compared to $521 million for full year 2013. The increase was primarily due to volume growth in south and west Texas, and north Louisiana, and contributions from the PVR, Eagle Rock and Hoover acquisitions.

Total average throughput volumes for the Gathering and Processing segment increased to 4.8 million MMbtu per day of natural gas for full-year 2014, including 2.3 million MMbtu per day related to the PVR, Eagle Rock and Hoover acquisitions, compared to 2.1 million MMbtu per day of natural gas for full-year 2013. Processed NGLs increased to an average of 149,000 barrels per day for full year 2014, compared to 90,000 barrels per day for full-year 2013.

Contract Services – Regency owns and operates a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. We also own and operate a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management.

Segment margin for the Contract Services segment, including both revenues from external customers as well as intersegment revenues, was $254 million for full-year 2014, compared to $204 million for full-year 2013. The increase in segment margin is primarily due to an increase in revenue generating horsepower, inclusive of intersegment revenue generating horsepower. As of December 31, 2014, the Contract Services segment’s revenue generating horsepower, including intersegment revenue generating horsepower, increased to 1,303,000, compared to 1,049,000 as of December 31, 2013, inclusive of 28,000 and 44,000, respectively, of revenue generating horsepower utilized by the Gathering and Processing segment.

Natural Resources - Regency is involved in the management of coal and natural resource properties and the related collection of royalties. The Partnership also earns revenues from other land management activities, including selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. This segment included the Partnership’s 50% interest in Coal Handling, which owned and operated end-user coal handling facilities. Regency purchased the remaining 50% interest in Coal Handling, effective December 31, 2014.

Natural Resources segment margin was $58 million from March 21, 2014 (the date of the acquisition) to December 31, 2014. Coal royalty tonnage for the same period was 11,265 for an average royalty per ton of $3.91.

Corporate – The Corporate segment comprises our corporate offices. Segment margin in the Corporate segment was $12 million for full-year 2014, compared to $18 million for full-year 2013.

Natural Gas Transportation – Regency owns a 49.99% general partner interest in RIGS Haynesville Partnership Co. (“HPC”), which owns the Regency Intrastate Gas System (“RIGS”), a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets, and a 50% membership interest in Midcontinent Express Pipeline (“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.

RIGS consists solely of the Regency Intrastate Gas System and is operated by Regency. Income from unconsolidated affiliates for RIGS was $27 million for full year 2014, compared to $30 million for full year 2013. Total throughput volumes for RIGS averaged 662,000 MMbtu per day of natural gas for full-year 2014, compared to 648,000 MMbtu per day for full-year 2013.

The MEP Joint Venture consists solely of MEP and is operated by Kinder Morgan Energy Partners L.P. Income from unconsolidated affiliates for the MEP Joint Venture was $45 million for full-year 2014, compared to $40 million for full-year 2013. Total throughput volumes for the MEP Joint Venture averaged 1.2 million MMbtu per day of natural gas for full-year 2014 and 1.3 million MMbtu per day for full-year 2013.

NGL Services – Regency owns a 30% membership interest in the Lone Star Joint Venture, which owns a diverse set of midstream energy assets including NGL pipelines, storage, fractionation and processing facilities located in Texas, New Mexico, Mississippi and Louisiana. The Lone Star Joint Venture is operated by Energy Transfer Partners, L.P.

Income from unconsolidated affiliates for NGL Services was $116 million for full-year 2014, compared to $64 million for full-year 2013. Transportation volumes averaged 211,000 barrels per day for full-year 2014, compared to 164,000 barrels per day for full-year 2013. Refinery Services throughput averaged 14,000 barrels per day for full-year 2014, compared to 13,000 barrels per day for full-year 2013. NGL Fractionation volumes for the first two fractionators, which came online in December 2012 and November 2013, respectively, averaged 179,000 barrels per day for full-year 2014, compared to 78,000 barrels per day for full-year 2013.

ORGANIC GROWTH

For the year ended December 31, 2014, Regency incurred $1.2 billion of growth capital expenditures: $749 million for the Gathering and Processing segment, $325 million for the Contract Services segment, $99 million for the NGL Services segment and $4 million for the Natural Gas Transportation segment.

For the year ended December 31, 2014, Regency incurred $98 million of maintenance capital expenditures.

In 2015, Regency expects to invest approximately $1.6 billion in growth capital expenditures, of which $1 billion is related to the Gathering and Processing segment, $400 million is related to the NGL Services segment and $200 million is related to the Contract Services segment.

In addition, Regency expects to invest approximately $100 million in maintenance capital expenditures in 2015, including its proportionate share related to joint ventures.

CASH DISTRIBUTIONS

On January 26, 2015, Regency announced a cash distribution of $0.5025 per outstanding common unit for the fourth quarter ended December 31, 2014. This distribution is equivalent to $2.01 per outstanding common unit on an annual basis and was paid on February 13, 2015, to unitholders of record at the close of business on February 6, 2015.

Based on the terms of the partnership agreement, the Series A Preferred Units were paid a quarterly distribution of $0.445 per unit for the fourth quarter-ended December 31, 2014, on the same schedule as set forth above.

For the full-year 2014, Regency generated $786 million in distributable cash flow, representing 0.97 times the amount required to cover its announced distribution to unitholders.

Regency makes distribution determinations based on its distributable cash flow and the perceived sustainability of distribution levels over an extended period. In addition to considering the cash available for distribution generated during the quarter, Regency takes into account cash reserves established with respect to prior distributions, seasonality of results, timing of organic growth projects and its internal forecasts of adjusted EBITDA and distributable cash flow over an extended period. Distributions are determined by the Board of Directors and are driven by the long-term sustainability of the business.

TELECONFERENCE

Regency Energy Partners will hold a quarterly conference call to discuss its fourth-quarter and full-year 2014 results on Thursday, February 19, 2015, at 10 a.m. Central Time (11 a.m. Eastern Time).

The dial-in number for the call is 1-866-700-0133 in the United States, or +1-617-213-8831 outside the United States, passcode 74671930. A live webcast of the call may be accessed on the Investor Relations page of Regency’s website at www.regencyenergy.com. The call will be available for replay for seven days by dialing 1-888-286-8010 (from outside the U.S., +1-617-801-6888) passcode 78485780. A replay of the broadcast will also be available on the Partnership’s website for 30 days.

NON-GAAP FINANCIAL INFORMATION

This press release and the accompanying financial schedules include the non-GAAP financial measures of:

• EBITDA;
• adjusted EBITDA;
• distributable cash flow;
• segment margin;
• total segment margin;
• adjusted segment margin; and
• adjusted total segment margin.

These financial metrics are key measures of the Partnership’s financial performance. The accompanying schedules provide reconciliations of these non-GAAP financial measures to their most directly-comparable financial measures calculated and presented in accordance with accounting principles generally accepted in the United States of America ("GAAP"). Our non-GAAP financial measures should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as a measure of operating performance, liquidity or ability to service debt obligations. Reconciliations of these non-GAAP financial measures to our GAAP financial statements are included in the Appendix.

We define EBITDA as net income (loss) plus interest expense, provision for income taxes and depreciation, depletion and amortization expense, and impairment expense. We define adjusted EBITDA as EBITDA plus or minus the following:

• non-cash loss (gain) from commodity and embedded derivatives;
• non-cash unit-based compensation;
• loss (gain) on asset sales, net;
• (gain) loss on debt refinancing;
• other non-cash (income) expense, net;
• acquisition costs;
• our interest in ELG and ORS adjusted EBITDA less EBITDA attributable to ELG and ORS;
• our interest in adjusted EBITDA from unconsolidated affiliates less income from unconsolidated affiliates; and
• other adjustments.

These measures are used as supplemental measures by our management and by external users of our financial statements such as investors, banks, research analysts and others, to assess:

• financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
• the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our unitholders and General Partner;
• our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and
• the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Adjusted EBITDA is the starting point in determining distributable cash flow, which is an important non-GAAP financial measure for a publicly traded partnership.

We define distributable cash flow as adjusted EBITDA:

• minus interest expense, excluding capitalized interest;
• minus maintenance capital expenditures;
• minus distributions to Series A Preferred Units;
• plus cash proceeds from asset sales, if any; and
• other adjustments.

Distributable cash flow is used as a supplemental liquidity measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to approximate the amount of operating surplus generated by us during a specific period and to assess our ability to make cash distributions to our unitholders and our general partner. Distributable cash flow is not the same measure as operating surplus or available cash, both of which are defined in our partnership agreement.

Neither EBITDA nor adjusted EBITDA should be considered an alternative to, or more meaningful than net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. EBITDA and adjusted EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate EBITDA or adjusted EBITDA in the same manner. EBITDA and adjusted EBITDA do not include interest expense, income tax expense or depreciation, depletion and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we use capital assets, depreciation, depletion and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net earnings determined under GAAP, as well as EBITDA and adjusted EBITDA, to evaluate our performance.

We define segment margin, generally, as revenues minus cost of sales. We calculate our Gathering and Processing segment margin and Natural Gas Transportation segment margin as revenues generated from operations less the cost of natural gas and NGLs purchased and other costs of sales, including third-party transportation and processing fees. We do not record segment margin for our investments in unconsolidated affiliates (HPC, MEP, Lone Star, Ranch JV, Aqua – PVR, Coal Handling and Sweeny JV) because we record our ownership percentages of their net income as income from unconsolidated affiliates in accordance with the equity method of accounting. We calculate our Contract Services segment margin as revenues generated from our contract compression and treating operations minus direct costs, primarily repairs, associated with those revenues. Segment margin for the Natural Resources segment margin is generally equal to total revenues as there is typically minimal cost of sales associated with the management and leasing of properties. We calculate total segment margin as the sum of segment margin of our segments less intersegment eliminations. We define adjusted segment margin as segment margin adjusted for non-cash (gains) losses from commodity derivatives, the 40% of ELG margin attributable to the holder of the noncontrolling interest, the 25% ORS margin attributable to the holder of the noncontrolling interest, and our 33.33% portion of Ranch JV margin. Adjusted total segment margin equals the sum of our operating segments’ adjusted segment margins or segment margins, as applicable, including intersegment eliminations.

Total segment margin and adjusted total segment margin are included as a supplemental disclosure because they are primary performance measures used by our management as they represent the result of product purchases and sales, a key component of our operations. We believe total segment margin and adjusted total segment margin are important measures because they are directly related to our volumes and commodity price changes.

Operation and maintenance expense is a separate measure used by management to evaluate operating performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operation and maintenance expense. These expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. We do not deduct operation and maintenance expenses from total revenues in calculating total segment margin and adjusted total segment margin because we separately evaluate commodity volume and price changes.

As an indicator of our operating performance, total segment margin or adjusted total segment margin should not be considered an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Our total segment margin and adjusted total segment margin may not be comparable to a similarly titled measure of another company because other entities may not calculate these measures in the same manner.

FORWARD-LOOKING INFORMATION AND OTHER DISCLAIMERS

These and other risks and uncertainties are discussed in more detail in filings made by the Partnership with the Securities and Exchange Commission, which are available to the public. The Partnership undertakes no obligation to update publicly or to revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Regency Energy Partners LP (NYSE:RGP) is a growth-oriented, master limited partnership engaged in the gathering and processing, compression, treating and transportation of natural gas; the transportation, fractionation and storage of natural gas liquids; the gathering, transportation and terminaling of oil (crude and/or condensate) received from producers; and the management of coal and natural resource properties in the United States. Regency’s general partner is owned by Energy Transfer Equity, L.P. (NYSE:ETE). For more information, please visit Regency’s website at www.regencyenergy.com.