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| 8-K - REGENCY ENERGY PARTNERS LP FORM 8-K DATED AUGUST 8, 2013. - Regency Energy Partners LP | form8k.htm |
Exhibit 99.1
Regency Energy Partners Reports Second-Quarter 2013 Results
DALLAS, August 7, 2013 – Regency Energy Partners LP (NYSE: RGP), (“Regency” or the “Partnership”), announced today its financial results for the second-quarter ended June 30, 2013.
The results presented herein have been retrospectively adjusted to combine Regency’s results with the results of Southern Union Gathering Company (“SUGS”) beginning March 26, 2012, due to the as-if pooling accounting treatment required for an acquisition between commonly controlled entities.
For the second quarter of 2013, adjusted EBITDA was $155 million, compared to $138 million in the second quarter of 2012. This increase was primarily due to volume growth in the Gathering and Processing segment, driven by strong drilling activity in south and west Texas, and in north Louisiana.
Regency generated $101 million in distributable cash flow (“DCF”) for the second quarter of 2013, compared to $72 million in the second quarter of 2012. DCF for 2012 has been adjusted to remove the historical SUGS results, and DCF for 2013 includes only 2 months of contribution from SUGS.
For the second quarter of 2013, Regency reported net income of $10 million, compared to net income of $27 million for the second quarter of 2012. The decrease in net income was primarily related to a $16 million increase in O&M expense, a $16 million decrease in the non-cash gain (loss) recognized on the mark-to-market of the embedded derivative related to the Series A Preferred Units and a $13 million increase in interest expense, partially offset by a $19 million increase in total segment margin and a $7 million decrease in G&A expense.
“During the second quarter of 2013, gathering and processing volumes increased 18 percent, and NGL transportation volumes grew 22 percent, driven by further ramp up of our growth projects completed in the fourth and first quarters,” said Mike Bradley, president and chief executive officer of Regency. "In addition, revenue generating horsepower increased 14 percent as we continued to see strong demand for third-party compression services.”
“We have recently placed into service an additional 270 MMcf/d of processing capacity and 160 MMcf/d of treating capacity, and we expect these projects to contribute to further volume growth as they ramp up in 2013 and 2014,” continued Bradley.
REVIEW OF SEGMENT PERFORMANCE
Adjusted total segment margin increased 13 percent to $181 million for the second quarter of 2013, compared to $160 million for the second quarter of 2012.
Gathering and Processing – We provide “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 the pipeline-quality natural gas and NGLs to various markets and pipeline systems. This segment also includes our 33.33% membership interest in the Ranch JV, which processes natural gas delivered from the NGLs-rich Bone Spring and Avalon shale formations in west Texas. The SUGS assets are included in this segment.
Adjusted segment margin for the Gathering and Processing segment, which excludes non-cash gains and losses from commodity derivatives, and includes our ownership interests in the Edwards Lime JV (“ELG”) and the Ranch JV, increased to $132 million for the second quarter of 2013, compared to $115 million for the second quarter of 2012. The increase was primarily due to volume growth in south and west Texas, and north Louisiana.
Total throughput volumes for the Gathering and Processing segment increased to 2.2 million MMbtu per day of natural gas for the second quarter of 2013, compared to 1.8 million MMbtu per day of natural gas for the second quarter of 2012. Processed NGLs increased to 89,000 barrels per day for the second quarter of 2013, compared to 78,000 barrels per day for the second quarter of 2012.
Contract Services – We own and operate 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, increased to $49 million for the second quarter of 2013, compared to $45 million for the second quarter of 2012. As of June 30, 2013 and 2012, the Contract Services segment’s revenue generating horsepower, including intersegment revenue generating horsepower, increased to 938,000, compared to 825,000, inclusive of 41,000 and 86,000, respectively, of revenue generating horsepower utilized by our Gathering and Processing segment. The increase in revenue generating horsepower is primarily attributable to additional horsepower placed into service in south and west Texas for external customers.
Corporate – The Corporate segment comprises our corporate assets. Segment margin in the Corporate segment was $4 million for the second quarter of 2013, compared to $5 million for the second quarter of 2012.
Natural Gas Transportation – We own a 49.99% general partner interest in 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 the Midcontinent Express Pipeline (“MEP”), which owns an interstate natural gas pipeline with approximately 500 miles 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.
The Haynesville Joint Venture consists solely of RIGS and is operated by Regency. Income from unconsolidated affiliates for the Haynesville Joint Venture was $8 million for the second quarter of 2013, compared to $12 million for the second quarter of 2012. Total throughput volumes for the Haynesville Joint Venture averaged 0.7 million MMbtu per day of natural gas for the second quarter of 2013, compared to 0.9 million MMbtu per day for the second quarter of 2012. These decreases are primarily due to the expiration of certain contracts that were not renewed as well as a customer declaring bankruptcy, which contributed $1 million to the decrease.
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 $10 million for both the second quarter of 2013 and the second quarter of 2012. Total throughput volumes for the MEP Joint Venture averaged 1.3 million MMbtu per day of natural gas for the second quarter of 2013 and 1.4 million MMbtu per day for the second quarter of 2012.
NGL Services – We own a 30% membership interest in Lone Star, an entity owning a diverse set of midstream energy assets including pipelines, storage, fractionation and processing facilities located in Texas, Mississippi and Louisiana. The Lone Star Joint Venture owns and operates NGL storage, fractionation and transportation assets and is operated by Energy Transfer Partners, L.P. For the second quarter of 2013, income from unconsolidated affiliates for the Lone Star Joint Venture was $13 million, compared to $12 million for the second quarter of 2012. For the second quarter of 2013, total NGL transportation volumes averaged 163,000 barrels per day, compared to 133,000 barrels per day for the second quarter of 2012. Refinery Services throughput averaged 15,000 barrels per day for the second quarter of 2013, compared to 21,000 barrels per day for the second quarter of 2012. NGL Fractionation volumes for the first fractionator, which came online in December 2012, averaged 87,000 barrels per day for the second quarter of 2013.
ORGANIC GROWTH
For the six months ended June 30, 2013, Regency incurred $435 million of growth capital expenditures: $235 million for the Gathering and Processing segment, $135 million for the Contract Services segment, and $65 million for the NGL Services segment.
For the six months ended June 30, 2013, Regency incurred $20 million of maintenance capital expenditures.
In 2013, Regency expects to invest approximately $800 million in growth capital expenditures, of which $465 million is related to the Gathering and Processing segment, which includes expenditures related to SUGS growth projects; $175 million is related to the NGL Services segment and $160 million is related to the Contract Services segment.
In addition, Regency expects to invest approximately $45 million in maintenance capital expenditures in 2013, including its proportionate share related to joint ventures.
CASH DISTRIBUTIONS
On July 25, 2013, Regency announced a cash distribution of $0.465 per outstanding common unit for the second quarter ended June 30, 2013. This distribution is equivalent to $1.86 per outstanding common unit projected on an annualized basis and will be paid on August 14, 2013, to unitholders of record at the close of business on August 5, 2013.
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 second quarter ended June 30, 2013, on the same schedule as set forth above.
In the second quarter of 2013, Regency generated $101 million in DCF, representing 1.00 times the amount required to cover its announced distribution to unitholders.
Regency makes distribution determinations based on its DCF and the perceived sustainability of distribution levels over an extended period. In addition to considering the DCF 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 DCF 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 second-quarter 2013 results Thursday, August 8, 2013, at 10 a.m. Central Time (11 a.m. Eastern Time).
The dial-in number for the call is 1-877-703-6107 in the United States, or +1-857-244-7306 outside the United States, passcode 30411607. 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 37481455. 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:
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EBITDA;
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adjusted EBITDA;
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distributable cash flow;
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segment margin;
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total segment margin;
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adjusted segment margin; and
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adjusted total segment margin.
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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 and amortization expense. We define adjusted EBITDA as EBITDA plus or minus the following:
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non-cash loss (gain) from commodity and embedded derivatives;
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unit-based compensation expenses;
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loss (gain) on asset sales, net;
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loss on debt refinancing;
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other non-cash (income) expense, net;
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net income attributable to the Edwards Lime Joint Venture (“ELG”);
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partnership’s interest in ELG adjusted EBITDA; and
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our interest in adjusted EBITDA from unconsolidated affiliates less income from unconsolidated affiliates.
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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:
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financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
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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;
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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
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the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
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Adjusted EBITDA is the starting point in determining DCF, which is an important non-GAAP financial measure for a publicly traded partnership.
We define DCF as adjusted EBITDA:
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minus interest expense, excluding capitalized interest;
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minus maintenance capital expenditures;
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minus distributions to Series A Preferred Units;
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plus cash proceeds from asset sales, if any; and
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other adjustments.
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DCF 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. DCF 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 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 DCF. Because we use capital assets, depreciation 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 income 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 and Grey Ranch) 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. We calculate total segment margin as the total of segment margin of our five 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 and our 33.33% portion of Ranch JV margin. Our adjusted total segment margin equals the sum of our operating segments’ adjusted segment margins or segment margins, 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 management as they represent the results of product purchases and sales, a key component of our operations.
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 expenses. These expenses are largely independent of the volumes we transport or process but fluctuate depending on the activities performed during a specific period. We do not deduct operation and maintenance expenses from total revenue in calculating total segment margin and adjusted total segment margin because we separately evaluate commodity volume and price changes in these margin amounts.
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
This release includes “forward-looking” statements. Forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may” or similar expressions help identify forward-looking statements. Although we believe our forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, we cannot give any assurance that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. Additional risks include: volatility in the price of oil, natural gas, and natural gas liquids, declines in the credit markets and the availability of credit for the Partnership as well as for producers connected to the Partnership’s system and its customers, the level of creditworthiness of, and performance by the Partnership’s counterparties and customers, the Partnership's ability to access capital to fund organic growth projects and acquisitions, the Partnership’s ability to obtain debt and equity financing on satisfactory terms, the Partnership's use of derivative financial instruments to hedge commodity and interest rate risks, the amount of collateral required to be posted from time-to-time in the Partnership's transactions, changes in commodity prices, interest rates, and demand for the Partnership's services, changes in laws and regulations impacting the midstream sector of the natural gas industry, weather and other natural phenomena, industry changes including the impact of consolidations and changes in competition, the Partnership's ability to obtain required approvals for construction or modernization of the Partnership's facilities and the timing of production from such facilities, and the effect of accounting pronouncements issued periodically by accounting standard setting boards. Therefore, actual results and outcomes may differ materially from those expressed in such forward-looking statements.
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, contract compression, contract treating and transportation of natural gas and the transportation, fractionation and storage of natural gas liquids. 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.
CONTACT:
Investor Relations:
Lyndsay Hannah
Regency Energy Partners
Manager, Finance & Investor Relations
214-840-5477
ir@regencygas.com
Media Relations:
Vicki Granado
Granado Communications Group
214-599-8785
vicki@granadopr.com
Condensed Consolidated Balance Sheets
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Regency Energy Partners LP
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Condensed Consolidated Balance Sheets
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($ in millions)
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June 30, 2013
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December 31, 2012
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Assets
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Current assets
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$ | 345 | $ | 340 | ||
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Property, plant and equipment, net
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4,073 | 3,686 | ||||
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Investment in unconsolidated affiliates
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2,224 | 2,214 | ||||
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Other assets, net
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55 | 43 | ||||
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Intangible assets, net
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696 | 712 | ||||
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Goodwill
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1,128 | 1,128 | ||||
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Total Assets
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$ | 8,521 | $ | 8,123 | ||
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Liabilities and Partners' Capital and Noncontrolling Interest
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Current liabilities
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$ | 409 | $ | 489 | ||
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Other long-term liabilities
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85 | 64 | ||||
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Long-term debt
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2,935 | 2,157 | ||||
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Series A Preferred Units
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73 | 73 | ||||
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Partners' capital
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4,929 | 3,530 | ||||
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Member's equity
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- | 1,733 | ||||
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Noncontrolling interest
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90 | 77 | ||||
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Total Partners' Capital and Noncontrolling Interest
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5,019 | 5,340 | ||||
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Total Liabilities and Partners' Capital and Noncontrolling Interest
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$ | 8,521 | $ | 8,123 | ||
Condensed Consolidated Statements of Operations
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Regency Energy Partners LP
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Condensed Consolidated Statements of Operations
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($ in millions)
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Three Months Ended June 30,
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2013
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2012
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REVENUES
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$ | 639 | $ | 511 | ||
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OPERATING COSTS AND EXPENSES
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Cost of sales
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445 | 336 | ||||
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Operation and maintenance
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73 | 57 | ||||
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General and administrative
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18 | 25 | ||||
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Loss on asset sales, net
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1 | 2 | ||||
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Depreciation and amortization
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68 | 69 | ||||
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Total operating costs and expenses
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605 | 489 | ||||
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OPERATING INCOME
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34 | 22 | ||||
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Income from unconsolidated affiliates
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31 | 34 | ||||
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Interest expense, net
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(41 | ) | (28 | ) | ||
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Loss on debt refinancing, net
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(7 | ) | (8 | ) | ||
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Other income and deductions, net
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(7 | ) | 8 | |||
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INCOME BEFORE INCOME TAXES
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10 | 28 | ||||
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Income tax expense (benefit)
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(1 | ) | - | |||
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NET INCOME
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$ | 11 | $ | 28 | ||
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Net income attributable to noncontrolling interest
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(1 | ) | (1 | ) | ||
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NET INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP
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$ | 10 | $ | 27 | ||
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Amount allocated to common units
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$ | 13 | $ | 23 | ||
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Weighted average number of common units outstanding
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193,065,183 | 170,107,060 | ||||
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Basic income per common unit
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$ | 0.07 | $ | 0.14 | ||
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Diluted income per common unit
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$ | 0.07 | $ | 0.10 | ||
Segment Financial and Operating Data
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Three Months Ended June 30,
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2013
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2012
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($ in millions)
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Gathering and Processing Segment
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Financial data:
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Segment margin
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$ | 145 | $ | 130 | ||
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Adjusted segment margin
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132 | 115 | ||||
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Operating data:
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Throughput (MMbtu/d)
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2,178,000 | 1,839,000 | ||||
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NGL gross production (Bbls/d)
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89,100 | 77,800 | ||||
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Three Months Ended June 30,
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2013
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2012
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($ in millions)
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Contract Services
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Financial data:
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Segment margin
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$ | 49 | $ | 45 | ||
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Operating data:
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Revenue generating horsepower, including intercompany revenue generating horsepower
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938,000 | 825,000 | ||||
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Three Months Ended June 30,
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2013
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2012
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($ in millions)
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Corporate Segment
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Financial data:
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Segment margin
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$ | 4 | $ | 5 | ||
The following provides key performance measures for 100% of the Haynesville Joint Venture, the MEP Joint Venture, the Lone Star Joint Venture and the Ranch Joint Venture
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Three Months Ended June 30,
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2013
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2012
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Haynesville Joint Venture
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Financial data:
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Adjusted EBITDA
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$ | 27 | $ | 36 | ||
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Operating data:
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Throughput (MMbtu/d)
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657,950 | 903,344 | ||||
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Three Months Ended June 30,
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2013
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2012
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MEP Joint Venture
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Financial data:
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Adjusted EBITDA
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$ | 51 | $ | 51 | ||
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Operating data:
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Throughput (MMbtu/d)
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1,263,734 | 1,418,206 | ||||
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Three Months Ended June 30,
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2013
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2012
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Lone Star Joint Venture
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Financial data:
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Adjusted EBITDA
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$ | 65 | $ | 53 | ||
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Operating data:
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NGL Transportation - Throughput (Bbls/d) (1)
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162,552 | 133,429 | ||||
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Refinery - Throughput (Bbls/d)
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14,748 | 20,575 | ||||
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Fractionation - Throughput (Bbls/d) (2)
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86,947 | - | ||||
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(1) Includes Gateway Pipeline throughput which was placed in service in December 2012
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(2) Fractionator began operations in December 2012
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Three Months Ended June 30,
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2013
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2012
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Ranch Joint Venture
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Financial data:
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Adjusted EBITDA
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$ | 2 | $ | - | ||
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Operating data:
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Throughput (MMbtu/d)
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68,522 | 4,744 | * | |||
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*Ranch Joint Venture's Refrigeration Processing Plant started operating in June 2012.
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Reconciliation of Non-GAAP Measures to GAAP Measures
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Three Months Ended June 30,
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2013
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2012
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($ in millions)
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Net income
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$ | 11 | $ | 28 | ||
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Add (deduct):
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Interest expense, net
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41 | 28 | ||||
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Depreciation and amortization
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68 | 69 | ||||
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EBITDA (1)
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$ | 120 | $ | 125 | ||
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Add (deduct):
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Partnership's interest in unconsolidated affiliates' adjusted EBITDA (2)(3)(4)(5)
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60 | 60 | ||||
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Income from unconsolidated affiliates
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(31 | ) | (34 | ) | ||
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Non-cash gain from commodity and embedded derivatives
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(4 | ) | (22 | ) | ||
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Other income, net
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10 | 9 | ||||
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Adjusted EBITDA
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$ | 155 | $ | 138 | ||
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(1) Earnings before interest, taxes, depreciation and amortization.
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(2) 100% of Haynesville Joint Venture's Adjusted EBITDA is calculated as follows:
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Net income
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$ | 18 | $ | 26 | ||
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Add (deduct):
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Depreciation and amortization
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9 | 9 | ||||
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Interest expense, net
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- | 1 | ||||
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Adjusted EBITDA
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$ | 27 | $ | 36 | ||
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Average ownership interest
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49.99 | % | 49.99 | % | ||
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Partnership's interest in Adjusted EBITDA
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$ | 13 | $ | 18 | ||
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(3) 100% of MEP Joint Venture's Adjusted EBITDA is calculated as follows:
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Net income
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$ | 21 | $ | 21 | ||
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Add (deduct):
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Depreciation and amortization
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17 | 17 | ||||
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Interest expense, net
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13 | 13 | ||||
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Adjusted EBITDA
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$ | 51 | $ | 51 | ||
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Average ownership interest
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50.00 | % | 50.00 | % | ||
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Partnership's interest in Adjusted EBITDA
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$ | 26 | $ | 26 | ||
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(4) 100% of Lone Star Joint Venture's Adjusted EBITDA is calculated as follows:
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Net income
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$ | 44 | $ | 41 | ||
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Add (deduct):
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Depreciation and amortization
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20 | 13 | ||||
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Other expenses, net
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1 | (1 | ) | |||
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Adjusted EBITDA
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$ | 65 | $ | 53 | ||
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Average ownership interest
|
30.00 | % | 30.00 | % | ||
|
Partnership's interest in Adjusted EBITDA
|
$ | 20 | $ | 16 | ||
|
(5) 100% of Ranch Joint Venture's Adjusted EBITDA is calculated as follows:
|
||||||
|
Net income (loss)
|
$ | 1 | $ | - | ||
|
Add (deduct):
|
||||||
|
Depreciation and amortization
|
1 | - | ||||
|
Adjusted EBITDA
|
$ | 2 | $ | - | ||
|
Average ownership interest
|
33.33 | % | 33.33 | % | ||
|
Partnership's interest in Adjusted EBITDA
|
$ | 1 | $ | - | ||
Non-GAAP Adjusted Total Segment Margin to GAAP Net Income
|
Three Months Ended June 30,
|
||||||
|
2013
|
2012
|
|||||
|
($ in millions)
|
||||||
|
Net income
|
$ | 11 | $ | 28 | ||
|
Add (Deduct):
|
||||||
|
Operation and maintenance
|
73 | 57 | ||||
|
General and administrative
|
18 | 25 | ||||
|
Loss on asset sales, net
|
1 | 2 | ||||
|
Depreciation and amortization
|
68 | 69 | ||||
|
Income from unconsolidated affiliates
|
(31 | ) | (34 | ) | ||
|
Interest expense, net
|
41 | 28 | ||||
|
Loss on debt refinancing, net
|
7 | 8 | ||||
|
Other income and deductions, net
|
7 | (8 | ) | |||
|
Income tax benefit
|
(1 | ) | - | |||
|
Total Segment Margin
|
194 | 175 | ||||
|
Non-cash gain from commodity derivatives
|
(12 | ) | (14 | ) | ||
|
Segment margin related to the noncontrolling interest
|
(2 | ) | (1 | ) | ||
|
Segment margin related to ownership percentage in Ranch JV
|
1 | - | ||||
|
Adjusted Total Segment Margin
|
$ | 181 | $ | 160 | ||
|
Gathering & Processing Segment Margin
|
$ | 145 | $ | 130 | ||
|
Non-cash gain from commodity derivatives
|
(12 | ) | (14 | ) | ||
|
Segment margin related to the noncontrolling interest
|
(2 | ) | (1 | ) | ||
|
Segment margin related to ownership percentage in Ranch JV
|
1 | - | ||||
|
Adjusted Gathering and Processing Segment Margin
|
132 | 115 | ||||
|
Natural Gas Transportation Segment Margin
|
- | - | ||||
|
Contract Services Segment Margin
|
49 | 45 | ||||
|
Corporate Segment Margin
|
4 | 5 | ||||
|
Inter-segment Elimination
|
(4 | ) | (5 | ) | ||
|
Adjusted Total Segment Margin
|
$ | 181 | $ | 160 | ||
Reconciliation of distributable cash flow to net cash flows provided by operating activities and to net income
|
Three Months Ended June 30,
|
||||||
|
2013
|
2012
|
|||||
|
($ in millions)
|
||||||
|
Net cash flows provided by operating activities
|
$ | 112 | $ | 53 | ||
|
Add (deduct):
|
||||||
|
Depreciation and amortization, including debt issuance cost, bond premium and excess fair value of unconsolidated affiliates amortization
|
(68 | ) | (70 | ) | ||
|
Income from unconsolidated affiliates
|
31 | 34 | ||||
|
Derivative valuation change
|
1 | 15 | ||||
|
Loss on asset sales, net
|
(1 | ) | (2 | ) | ||
|
Unit-based compensation expenses
|
(1 | ) | (1 | ) | ||
|
Cash flow changes in current assets and liabilities:
|
||||||
|
Trade accounts receivables, accrued revenues, and related party receivables
|
27 | (25 | ) | |||
|
Other current assets and other current liabilities
|
137 | 8 | ||||
|
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues
|
(57 | ) | 37 | |||
|
Distributions of earnings received from unconsolidated affiliates
|
(35 | ) | (34 | ) | ||
|
Other assets and liabilities
|
(135 | ) | 13 | |||
|
Net (Loss) Income
|
$ | 11 | $ | 28 | ||
|
Add:
|
||||||
|
Interest expense, net
|
41 | 28 | ||||
|
Depreciation and amortization
|
68 | 69 | ||||
|
EBITDA
|
$ | 120 | $ | 125 | ||
|
Add (deduct):
|
||||||
|
Partnership's interest in unconsolidated affiliates' adjusted EBITDA
|
60 | 60 | ||||
|
Income from unconsolidated affiliates
|
(31 | ) | (34 | ) | ||
|
Non-cash loss (gain) from commodity and embedded derivatives
|
(4 | ) | (22 | ) | ||
|
Other income, net
|
10 | 9 | ||||
|
Adjusted EBITDA
|
$ | 155 | $ | 138 | ||
|
Add (deduct):
|
||||||
|
Interest expense, excluding capitalized interest
|
(46 | ) | (41 | ) | ||
|
Maintenance capital expenditures
|
(13 | ) | (7 | ) | ||
|
SUGS Contribution Agreement adjustment *
|
9 | (23 | ) | |||
|
Proceeds from asset sales
|
5 | 7 | ||||
|
Other adjustments
|
(9 | ) | (2 | ) | ||
|
Distributable cash flow
|
$ | 101 | $ | 72 | ||
|
* Includes an adjustment to DCF related to the historical SUGS operations for the time period prior to the Partnership's acquisition.
|
||||||
Reconciliation of distributable cash flow to net cash flows provided by operating activities and to net income
|
Six Months Ended June 30,
|
||||||
|
2013
|
2012
|
|||||
|
($ in millions)
|
||||||
|
Net cash flows provided by operating activities
|
$ | 195 | $ | 102 | ||
|
Add (deduct):
|
||||||
|
Depreciation and amortization, including debt issuance cost, bond premium and excess fair value of unconsolidated affiliates amortization
|
(137 | ) | (125 | ) | ||
|
Income from unconsolidated affiliates
|
66 | 66 | ||||
|
Derivative valuation change
|
(17 | ) | 18 | |||
|
Loss on asset sales, net
|
(2 | ) | (2 | ) | ||
|
Unit-based compensation expenses
|
(3 | ) | (2 | ) | ||
|
Cash flow changes in current assets and liabilities:
|
||||||
|
Trade accounts receivables, accrued revenues, and related party receivables
|
41 | (29 | ) | |||
|
Other current assets and other current liabilities
|
51 | (3 | ) | |||
|
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues
|
(10 | ) | 69 | |||
|
Distributions of earnings received from unconsolidated affiliates
|
(71 | ) | (63 | ) | ||
|
Other assets and liabilities
|
(131 | ) | 12 | |||
|
Net (Loss) Income
|
$ | (18 | ) | $ | 43 | |
|
Add:
|
||||||
|
Interest expense, net
|
78 | 57 | ||||
|
Depreciation and amortization
|
133 | 122 | ||||
|
Income tax expense (benefit)
|
(3 | ) | - | |||
|
EBITDA
|
$ | 190 | $ | 222 | ||
|
Add (deduct):
|
||||||
|
Non-cash loss (gain) from commodity and embedded derivatives
|
14 | (24 | ) | |||
|
Unit-based compensation expenses
|
3 | 1 | ||||
|
Loss on asset sales, net
|
2 | 2 | ||||
|
Loss on debt extinguishment
|
7 | 8 | ||||
|
Income from unconsolidated affiliates
|
(66 | ) | (66 | ) | ||
|
Partnership's interest in unconsolidated affiliates' adjusted EBITDA
|
123 | 116 | ||||
|
Other income, net
|
1 | (2 | ) | |||
|
Adjusted EBITDA
|
$ | 274 | $ | 257 | ||
|
Add (deduct):
|
||||||
|
Interest expense, excluding capitalized interest
|
(81 | ) | (76 | ) | ||
|
Maintenance capital expenditures
|
(20 | ) | (14 | ) | ||
|
SUGS Contribution Agreement adjustment *
|
16 | (8 | ) | |||
|
Proceeds from asset sales
|
16 | 20 | ||||
|
Other adjustments
|
(4 | ) | (6 | ) | ||
|
Distributable cash flow
|
$ | 201 | $ | 173 | ||
|
* Includes an adjustment to DCF related to the historical SUGS operations for the time period prior to the Partnership's acquisition.
|
||||||