Exhibit 99.1
an
 | News Release | |||
| www.dcppartners.com | ||||
| MEDIA AND INVESTOR RELATIONS CONTACT: | Andrea Attel | |||
| August 6, 2013 | Phone: | 303/605-1741 | ||
| 24-Hour: | 720/235-6433 | |||
DCP MIDSTREAM PARTNERS REPORTS STRONG SECOND QUARTER 2013 RESULTS
| • | Second quarter 2013 Distributable Cash Flow up over 200 percent from second quarter 2012 |
| • | Dropped down the LaSalle Plant in the DJ Basin and a one-third interest in the 435-mile Front Range Pipeline with a combined investment of over $400 million |
| • | Quarterly distribution increase in line with 2013 distribution growth forecast |
DENVER - DCP Midstream Partners, LP (NYSE: DPM), or the Partnership, today reported financial results for the three and six months ended June 30, 2013. The table below reflects the results for the three and six months ended June 30, 2013 and 2012 on a consolidated basis and for the 2012 periods as originally reported.
SECOND QUARTER 2013 SUMMARY RESULTS
| Three Months Ended | Six Months Ended | |||||||||||||||||||||||
| June 30, | June 30, | |||||||||||||||||||||||
| 2013 | 2012 (3) | As Reported in 2012 | 2013 (3) | 2012 (3)(4) | As Reported in 2012 | |||||||||||||||||||
| (Unaudited) | ||||||||||||||||||||||||
| (Millions, except per unit amounts) | ||||||||||||||||||||||||
Net income attributable to partners(1)(5) | $ | 102 | $ | 85 | $ | 79 | $ | 154 | $ | 119 | $ | 102 | ||||||||||||
Net income per limited partner unit - basic and diluted(1)(5) | $ | 1.11 | $ | 1.33 | $ | 1.33 | $ | 1.64 | $ | 1.64 | $ | 1.64 | ||||||||||||
Adjusted EBITDA(2) | $ | 79 | $ | 44 | $ | 35 | $ | 173 | $ | 146 | $ | 119 | ||||||||||||
Adjusted net income attributable to partners(2) | $ | 44 | $ | 20 | $ | 14 | $ | 106 | $ | 78 | $ | 61 | ||||||||||||
Adjusted net income per limited partner unit(2) - basic and diluted | $ | 0.36 | $ | 0.08 | $ | 0.08 | $ | 0.97 | $ | 0.81 | $ | 0.81 | ||||||||||||
Distributable cash flow(2) | $ | 68 | ** | $ | 22 | $ | 145 | ** | $ | 77 | ||||||||||||||
| (1) | Includes non-cash commodity derivative mark-to-market gains of $58 million and $65 million for the three months ended June 30, 2013 and 2012, respectively. Includes non-cash commodity derivative mark-to-market gains of $48 million and $42 million for the six months ended June 30, 2013 and 2012, respectively. |
| (2) | Denotes a financial measure not presented in accordance with U.S. generally accepted accounting principles, or GAAP. Each such non-GAAP financial measure is defined below under “Non-GAAP Financial Information”, and each is reconciled to its most directly comparable GAAP financial measures under “Reconciliation of Non-GAAP Financial Measures” below. |
| (3) | Includes our 80 percent interest in the Eagle Ford system, retrospectively adjusted. We acquired a 33.33 percent interest in the Eagle Ford system in November 2012, and a 46.67 percent interest in March 2013. Transfers of net assets between entities under common control are accounted for as if the transactions had occurred at the beginning of the period, and prior |
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years are retrospectively adjusted to furnish comparative information similar to the pooling method. In addition, results are presented as originally reported in 2012 for comparative purposes.
| (4) | Includes our 100 percent interest in Southeast Texas, retrospectively adjusted. We acquired a 33.33 percent interest in Southeast Texas in January 2011, and a 66.67 percent interest in March 2012. Transfers of net assets between entities under common control are accounted for as if the transactions had occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information similar to the pooling method. In addition, results are presented as originally reported in 2012 for comparative purposes. |
| (5) | The Partnership recognized $3 million of lower of cost or market adjustments during the three and six months ended June 30, 2013, and $14 million and $19 million of lower of cost or market adjustments during the three and six months ended June 30, 2012, respectively. |
** Distributable cash flow has not been calculated under the pooling method.
DROPPED DOWN LASALLE PLANT AND FRONT RANGE PIPELINE
On August 5, 2013, the Partnership completed the dropdowns from DCP Midstream, the owner of our general partner, of the LaSalle Plant and a one-third interest in the Front Range Pipeline at a combined investment of over $400 million, including follow on capital. The transactions, which are subject to certain purchase price adjustments, were financed at closing through borrowings under the Partnership's revolving credit facility.
The LaSalle Plant is part of the DCP enterprise's ongoing program to expand its gathering and processing presence in the prolific DJ Basin.
LaSalle Plant highlights include:
• | 110 million cubic feet per day (MMcf/d) deep-cut cryogenic processing plant under construction with plans to expand to 160 MMcf/d in the first half of 2014 |
• | A 15-year fee-based processing agreement with DCP Midstream providing a fixed demand charge, along with a throughput fee on all volumes processed |
This fee-based plant will become part of an eight-plant system with approximately 600 MMcf/d of total processing capacity owned by the DCP enterprise. These plants serve producers in the quickly growing Niobrara shale play that is part of the DJ Basin. The LaSalle Plant is expected to be in service in the second half of 2013. The total investment for the LaSalle Plant is $242 million, of which $209 million was paid at closing with an estimated $33 million for the cost to complete and expand the plant to 160 MMcf/d.
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Front Range Pipeline highlights include:
• | One-third interest in Front Range Pipeline, an NGL pipeline with affiliates of Enterprise Products Partners L.P. and Anadarko Petroleum Corporation, each owning a one-third interest, which is operated by Enterprise |
• | Fee-based revenues backstopped by ship or pay arrangements with DCP Midstream and Anadarko |
• | 435-mile, 16-inch diameter natural gas liquids (NGL) pipeline |
• | 150,000 barrels per day of NGL pipeline capacity, expandable to approximately 230,000 barrels per day |
The Front Range Pipeline will provide much needed takeaway capacity for the expanding production of natural gas liquids in the DJ Basin, serving the Niobrara shale play. The pipeline will originate in Weld County, Colorado, and extend approximately 435 miles to Skellytown, Texas. With connections to the Enterprise-operated Mid-America and Texas Express pipelines, the Front Range Pipeline will provide producers in the DJ Basin with reliable takeaway capacity and market access to the Gulf Coast, the largest NGL market in the United States. The pipeline operator expects the Front Range Pipeline to be mechanically complete in the fourth quarter of 2013. The total investment for the one-third interest in Front Range Pipeline is $172 million, of which $86 million was paid at closing with an estimated $86 million for the cost to complete construction.
SECOND QUARTER HIGHLIGHTS
• | We are on target to deliver on the key elements of our 2013 business plan |
| ◦ | Second quarter 2013 Distributable Cash Flow was up over 200 percent from second quarter 2012 |
| ◦ | Financial results in line with 2013 Distributable Cash Flow forecast |
| ◦ | Quarterly distribution increase in line with 2013 distribution growth forecast |
• | With the dropdown of the additional 47 percent interest in the Eagle Ford system in the first quarter and the completion of the LaSalle Plant and Front Range Pipeline dropdowns, we have exceeded our $1 billion of targeted dropdowns in 2013 and are on track to deliver approximately $2.7 billion of dropdowns and organic growth in 2013/2014. |
In summary, our dropdown strategy with DCP Midstream, visible pipeline of organic growth projects, as well as solid financial results, position us well to achieve our 2013 forecast.
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PRESIDENT'S PERSPECTIVE
“I couldn't be more pleased with our second quarter results,” said Bill Waldheim, president of the Partnership. “The year-to-date financial results and distribution growth are in line with our 2013 forecast. With the completion of the dropdowns of the fee-based LaSalle Plant and Front Range Pipeline, we are expanding into another high growth area. This is the second year in a row that we have exceeded our $1 billion of targeted dropdowns. Once these assets are placed into service they will be accretive and are another example of how we are partnering with our general partner to fund the growth of the DCP enterprise.”
CONSOLIDATED FINANCIAL RESULTS
Consolidated results are shown using the pooling method of accounting, which includes results associated with DCP Midstream's ownership interests in the Eagle Ford system and Southeast Texas during its periods of ownership. While the Partnership hedges the majority of its commodity risk, prior period results reflect DCP Midstream's unhedged portion of its ownership interest in the Eagle Ford system and Southeast Texas during those periods.
Adjusted EBITDA for the three months ended June 30, 2013, increased to $79 million from $44 million for the three months ended June 30, 2012. Adjusted EBITDA for the six months ended June 30, 2013, increased to $173 million from $146 million for the six months ended June 30, 2012. These results reflect increased volumes on our Eagle Ford system, the dropdown of the Mont Belvieu fractionators and higher margins at the Marysville storage facility, partially offset by hedge settlement timing on storage. Adjusted EBITDA for the three and six months ended June 30, 2012, included a non-cash write down of $14 million and $15 million, respectively, to reflect propane inventory carrying costs at the lower of cost or market price (“LCM Adjustment”) for our wholesale propane logistics segment.
On July 25, 2013, the Partnership announced a quarterly distribution of $0.71 per limited partner unit. This represents an increase of 1.4 percent over the last quarterly distribution and an increase of 6 percent over the distribution declared in the second quarter of 2012. Our distributable cash flow of $68 million for the three months ended June 30, 2013, provided a 1.0 times distribution coverage ratio adjusted for the timing of actual distributions paid during the quarter. The distribution coverage ratio adjusted for the timing of actual distributions paid during the last four quarters was approximately 1.1 times.
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OPERATING RESULTS BY BUSINESS SEGMENT
Natural Gas Services - Adjusted segment EBITDA increased to $72 million for the three months ended June 30, 2013, from $69 million for the three months ended June 30, 2012, reflecting higher volumes at our Eagle Ford system and the operation of our fee-based wholly-owned Eagle Plant, partially offset by hedge settlement timing on storage.
Adjusted segment EBITDA decreased to $137 million for the six months ended June 30, 2013, from $161 million for the six months ended June 30, 2012, reflecting hedge settlement timing on storage, lower NGL prices, lower volumes across certain of our assets and timing of operating expenses, partially offset by higher volumes at our Eagle Ford system, the operation of our fee-based wholly-owned Eagle Plant and higher unit margins attributable to our natural gas storage and pipeline assets.
Results are shown using the pooling method of accounting, which includes the additional 47 percent of the Eagle Ford system for the three months ended March 31, 2013, and 80 percent of the Eagle Ford system for the six months ended June 30, 2012. Results also include 67 percent of Southeast Texas for the three months ended March 31, 2012. These results reflect the unhedged portion of the Eagle Ford system and Southeast Texas associated with DCP Midstream's ownership interest during those periods.
NGL Logistics - Adjusted segment EBITDA increased to $22 million for the three months ended June 30, 2013, from $11 million for the three months ended June 30, 2012. Adjusted segment EBITDA increased to $45 million for the six months ended June 30, 2013, from $23 million for the six months ended June 30, 2012. These results reflect the July 2012 dropdown of the Mont Belvieu fractionators, higher margins at the Marysville storage facility and higher throughput on certain of our pipelines.
Wholesale Propane Logistics - Adjusted segment EBITDA increased to $1 million for the three months ended June 30, 2013, from a loss of $19 million for the three months ended June 30, 2012, reflecting increased unit margins and the 2012 LCM Adjustment of $14 million.
Adjusted segment EBITDA increased to $23 million for the six months ended June 30, 2013, from a loss of $1 million for the six months ended June 30, 2012. The 2013 results reflect increased unit margins and the exporting of propane from the Chesapeake terminal partially
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offset by a non-cash write off of a discontinued construction project. 2012 results reflect the LCM Adjustment of $15 million and reduced demand as a result of near record warm weather.
CORPORATE AND OTHER
The changes in depreciation and amortization expense for the three and six months ended June 30, 2013, as compared to the three and six months ended June 30, 2012, reflect growth, as well as a change in the estimated useful lives of our assets.
CAPITALIZATION
At June 30, 2013, the Partnership had $1,740 million of total debt outstanding comprised of $1,590 million of senior notes and $150 million outstanding under our revolver. Total unused revolver capacity was approximately $850 million. Our leverage ratio pursuant to our credit facility for the quarter ended June 30, 2013, was approximately 3.7 times. Our effective interest rate on our overall debt position, as of June 30, 2013, was 3.7 percent.
COMMODITY DERIVATIVE ACTIVITY
The objective of our commodity risk management program is to protect downside risk in our distributable cash flow. We utilize mark-to-market accounting treatment for our commodity derivative instruments. Mark-to-market accounting rules require companies to record currently in earnings the difference between their contracted future derivative settlement prices and the forward prices of the underlying commodities at the end of the accounting period. Revaluing our commodity derivative instruments based on futures pricing at the end of the period creates assets or liabilities and associated non-cash gains or losses. Realized gains or losses from cash settlement of the derivative contracts occur monthly as our physical commodity sales are realized or when we rebalance our portfolio. Non-cash gains or losses associated with the mark-to-market accounting treatment of our commodity derivative instruments do not affect our distributable cash flow.
For the three months ended June 30, 2013, commodity derivative activity and total revenues included non-cash gains of $58 million. This compares to non-cash gains of $65 million for the three months ended June 30, 2012. Net hedge cash settlements for the three months ended June 30, 2013, were receipts of $13 million. Net hedge cash settlements for the three months ended June 30, 2012, were receipts of $10 million.
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For the six months ended June 30, 2013, commodity derivative activity and total revenues included non-cash gains of $48 million. This compares to non-cash gains of $42 million for the six months ended June 30, 2012. Net hedge cash settlements for the six months ended June 30, 2013, were receipts of $23 million. Net hedge cash settlements for the six months ended June 30, 2012, were receipts of $28 million. While our earnings will continue to fluctuate as a result of the volatility in the commodity markets, our commodity derivative contracts mitigate a substantial portion of the risk of weakening commodity prices thereby stabilizing distributable cash flows.
EARNINGS CALL
DCP Midstream Partners will hold a conference call to discuss second quarter results on Wednesday, August 7, 2013, at 9:00 a.m. ET. The dial-in number for the call is 1-800-446-1671 in the United States or 1-847-413-3362 outside the United States. A live webcast of the call can be accessed on the Investor section of DCP Midstream Partners' website at www.dcppartners.com. The conference confirmation number for login is 35272692. The call will be available for replay one hour after the end of the conference until Midnight ET on August 20, 2013, by dialing 1-888-843-7419 in the United States or 1-630-652-3042 outside the United States. The replay conference number is 35272692. A replay, transcript and presentation slides in PDF format will also be available by accessing the Investor section of the Partnership's website.
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NON-GAAP FINANCIAL INFORMATION
This press release and the accompanying financial schedules include the following non-GAAP financial measures: distributable cash flow, adjusted EBITDA, adjusted segment EBITDA, adjusted net income attributable to partners, and adjusted net income per limited partner unit. The accompanying schedules provide reconciliations of these non-GAAP financial measures to their most directly comparable GAAP financial measures. The Partnership's non-GAAP financial measures should not be considered in isolation or as an alternative to its financial measures presented in accordance with GAAP, including operating revenues, net income or loss attributable to partners, net cash provided by or used in operating activities or any other measure of liquidity or financial performance presented in accordance with GAAP as a measure of operating performance, liquidity or ability to service debt obligations and make cash distributions to unitholders. The non-GAAP financial measures presented by us may not be comparable to similarly titled measures of other companies because they may not calculate their measures in the same manner.
We define distributable cash flow as net cash provided by or used in operating activities, less maintenance capital expenditures, net of reimbursable projects, plus or minus adjustments for non-cash mark-to-market of derivative instruments, proceeds from divestiture of assets, net income attributable to noncontrolling interests net of depreciation and income tax, net changes in operating assets and liabilities, and other adjustments to reconcile net cash provided by or used in operating activities. Historical distributable cash flow is calculated excluding the impact of retrospective adjustments related to any acquisitions presented under the pooling method. Maintenance capital expenditures are capital expenditures made where we add on to or improve capital assets owned, or acquire or construct new capital assets, if such expenditures are made to maintain, including over the long-term, the Partnership's operating or earnings capacity. Non-cash mark-to-market of derivative instruments is considered to be non-cash for the purpose of computing distributable cash flow because settlement will not occur until future periods, and will be impacted by future changes in commodity prices and interest rates. Distributable cash flow is used as a supplemental liquidity and performance measure by the Partnership's management and by external users of its financial statements, such as investors, commercial banks, research analysts and others, to assess the Partnership's ability to make cash distributions to its unitholders and its general partner.
We define adjusted EBITDA as net income or loss attributable to partners less interest income, noncontrolling interest in depreciation and income tax expense and non-cash commodity derivative gains, plus interest expense, income tax expense, depreciation and amortization expense and non-cash commodity derivative losses. The commodity derivative non-cash losses and gains result from the marking to market of certain financial derivatives used by us for risk management purposes that we do not account for under the hedge method of accounting. These non-cash losses or gains may or may not be realized in future periods when the derivative contracts are settled, due to fluctuating commodity prices. We define adjusted segment EBITDA for each segment as segment net income or loss attributable to partners less non-cash commodity derivative gains for that segment, plus depreciation and amortization expense and non-cash commodity derivative losses for that segment, adjusted for any noncontrolling interest on depreciation and amortization expense for that segment. The Partnership's adjusted EBITDA equals the sum of its adjusted segment EBITDAs, plus general and administrative expense.
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Adjusted EBITDA is used as a supplemental liquidity and performance measure and adjusted segment EBITDA is used as supplemental performance measure by the Partnership's management and by external users of its financial statements, such as investors, commercial banks, research analysts and others to assess:
| • | financial performance of the Partnership's assets without regard to financing methods, capital structure or historical cost basis; |
| • | the Partnership's operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing methods or capital structure; |
| • | viability and performance of acquisitions and capital expenditure projects and the overall rates of return on investment opportunities; |
| • | performance of the Partnership's business excluding non-cash commodity derivative gains or losses; and |
| • | in the case of Adjusted EBITDA, the ability of the Partnership's assets to generate cash sufficient to pay interest costs, support its indebtedness, make cash distributions to its unitholders and general partner, and finance maintenance capital expenditures. |
We define adjusted net income attributable to partners as net income attributable to partners, plus non-cash derivative losses, less non-cash derivative gains. Adjusted net income per limited partner unit is then calculated from adjusted net income attributable to partners. These non-cash derivative losses and gains result from the marking to market of certain financial derivatives used by us for risk management purposes that we do not account for under the hedge method of accounting. Adjusted net income attributable to partners and adjusted net income per limited partner unit are provided to illustrate trends in income excluding these non-cash derivative losses or gains, which may or may not be realized in future periods when derivative contracts are settled, due to fluctuating commodity prices.
ABOUT DCP MIDSTREAM PARTNERS
DCP Midstream Partners, LP (NYSE: DPM) is a midstream master limited partnership engaged in the business of gathering, compressing, treating, processing, transporting, storing and selling natural gas; producing, fractionating, transporting, storing and selling NGLs and condensate; and transporting, storing and selling propane in wholesale markets. DCP Midstream Partners, LP is managed by its general partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCP Midstream GP, LLC, or the General Partner, which is wholly-owned by DCP Midstream, LLC, a system between Phillips 66 and Spectra Energy. For more information, visit the DCP Midstream Partners, LP website at www.dcppartners.com.
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CAUTIONARY STATEMENTS
This press release may contain or incorporate by reference forward-looking statements as defined under the federal securities laws regarding DCP Midstream Partners, LP, including projections, estimates, forecasts, plans and objectives. Although management believes that expectations reflected in such forward-looking statements are reasonable, no assurance can be given that such expectations will prove to be correct. In addition, these statements are subject to certain risks, uncertainties and other assumptions that are difficult to predict and may be beyond the Partnership's control. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership's actual results may vary materially from what management anticipated, estimated, projected or expected.
The key risk factors that may have a direct bearing on the Partnership's results of operations and financial condition are described in detail in the Partnership's annual and quarterly reports most recently filed with the Securities and Exchange Commission and other such matters discussed in the “Risk Factors” section of the Partnership's most recent Annual Report on Form 10-K and subsequent Quarterly Reports on Form 10-Q filed with the Securities and Exchange Commission. Investors are encouraged to closely consider the disclosures and risk factors contained in the Partnership's annual and quarterly reports filed from time to time with the Securities and Exchange Commission. The forward looking statements contained herein speak as of the date of this announcement. The Partnership undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Information contained in this press release is unaudited, and is subject to change.
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DCP MIDSTREAM PARTNERS, LP
FINANCIAL RESULTS AND
SUMMARY BALANCE SHEET DATA
(Unaudited)
| Three Months Ended | Six Months Ended | ||||||||||||||||||||||||
| June 30, | June 30, | ||||||||||||||||||||||||
| 2013 | 2012 | As Reported in 2012 | 2013 | 2012 | As Reported in 2012 | ||||||||||||||||||||
| (Millions, except per unit amounts) | |||||||||||||||||||||||||
| Sales of natural gas, propane, NGLs and condensate | $ | 643 | $ | 543 | $ | 297 | $ | 1,311 | $ | 1,333 | $ | 784 | |||||||||||||
| Transportation, processing and other | 61 | 50 | 42 | 124 | 102 | 85 | |||||||||||||||||||
| Gains from commodity derivative activity, net | 71 | 75 | 75 | 71 | 70 | 70 | |||||||||||||||||||
| Total operating revenues | 775 | 668 | 414 | 1,506 | 1,505 | 939 | |||||||||||||||||||
| Purchases of natural gas, propane and NGLs | (573 | ) | (490 | ) | (274 | ) | (1,159 | ) | (1,186 | ) | (706 | ) | |||||||||||||
| Operating and maintenance expense | (51 | ) | (50 | ) | (30 | ) | (96 | ) | (92 | ) | (56 | ) | |||||||||||||
| Depreciation and amortization expense | (23 | ) | (15 | ) | (10 | ) | (43 | ) | (49 | ) | (34 | ) | |||||||||||||
| General and administrative expense | (16 | ) | (17 | ) | (11 | ) | (32 | ) | (36 | ) | (22 | ) | |||||||||||||
| Other expense | — | — | — | (4 | ) | — | — | ||||||||||||||||||
| Total operating costs and expenses | (663 | ) | (572 | ) | (325 | ) | (1,334 | ) | (1,363 | ) | (818 | ) | |||||||||||||
| Operating income | 112 | 96 | 89 | 172 | 142 | 121 | |||||||||||||||||||
| Interest expense | (14 | ) | (11 | ) | (11 | ) | (26 | ) | (24 | ) | (24 | ) | |||||||||||||
| Earnings from unconsolidated affiliates | 8 | 2 | 2 | 16 | 8 | 8 | |||||||||||||||||||
| Income tax expense | — | — | — | (1 | ) | (1 | ) | (1 | ) | ||||||||||||||||
| Net income attributable to noncontrolling interests | (4 | ) | (2 | ) | (1 | ) | (7 | ) | (6 | ) | (2 | ) | |||||||||||||
| Net income attributable to partners | 102 | 85 | 79 | 154 | 119 | 102 | |||||||||||||||||||
| Net income attributable to predecessor operations | — | (6 | ) | — | (6 | ) | (20 | ) | (3 | ) | |||||||||||||||
| General partner's interest in net income | (16 | ) | (10 | ) | (10 | ) | (31 | ) | (18 | ) | (18 | ) | |||||||||||||
| Net income allocable to limited partners | $ | 86 | $ | 69 | $ | 69 | $ | 117 | $ | 81 | $ | 81 | |||||||||||||
| Net income per limited partner unit-basic and diluted | $ | 1.11 | $ | 1.33 | $ | 1.33 | $ | 1.64 | $ | 1.64 | $ | 1.64 | |||||||||||||
| Weighted-average limited partner units outstanding-basic and diluted | 77.3 | 51.9 | 51.9 | 71.3 | 49.4 | 49.4 | |||||||||||||||||||
| As Reported | ||||||||||||
| June 30, | December 31, | December 31, | ||||||||||
| 2013 | 2012 | 2012 | ||||||||||
| (Millions) | ||||||||||||
| Cash and cash equivalents | $ | 9 | $ | 2 | $ | 1 | ||||||
| Other current assets | 411 | 366 | 308 | |||||||||
| Property, plant and equipment, net | 2,679 | 2,550 | 1,727 | |||||||||
| Other long-term assets | 840 | 685 | 936 | |||||||||
| Total assets | $ | 3,939 | $ | 3,603 | $ | 2,972 | ||||||
| Current liabilities | $ | 410 | $ | 345 | $ | 234 | ||||||
| Long-term debt | 1,740 | 1,620 | 1,620 | |||||||||
| Other long-term liabilities | 39 | 44 | 35 | |||||||||
| Partners' equity | 1,533 | 1,405 | 1,048 | |||||||||
| Noncontrolling interests | 217 | 189 | 35 | |||||||||
| Total liabilities and equity | $ | 3,939 | $ | 3,603 | $ | 2,972 | ||||||
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DCP MIDSTREAM PARTNERS, LP
RECONCILIATION OF NON-GAAP FINANCIAL MEASURES
(Unaudited)
| Three Months Ended | Six Months Ended | ||||||||||||||||||||||||
| June 30, | June 30, | ||||||||||||||||||||||||
| 2013 | 2012 | As Reported in 2012 | 2013 | 2012 | As Reported in 2012 | ||||||||||||||||||||
| (Millions, except per unit amounts) | |||||||||||||||||||||||||
| Reconciliation of Non-GAAP Financial Measures: | |||||||||||||||||||||||||
| Net income attributable to partners | $ | 102 | $ | 85 | $ | 79 | $ | 154 | $ | 119 | $ | 102 | |||||||||||||
| Interest expense | 14 | 11 | 11 | 26 | 24 | 24 | |||||||||||||||||||
| Depreciation, amortization and income tax expense, net of noncontrolling interests | 21 | 13 | 10 | 41 | 45 | 35 | |||||||||||||||||||
| Non-cash commodity derivative mark-to-market | (58 | ) | (65 | ) | (65 | ) | (48 | ) | (42 | ) | (42 | ) | |||||||||||||
| Adjusted EBITDA | 79 | 44 | 35 | 173 | 146 | 119 | |||||||||||||||||||
| Interest expense | (14 | ) | (11 | ) | (11 | ) | (26 | ) | (24 | ) | (24 | ) | |||||||||||||
| Depreciation, amortization and income tax expense, net of noncontrolling interests | (21 | ) | (13 | ) | (10 | ) | (41 | ) | (45 | ) | (35 | ) | |||||||||||||
| Other | — | — | — | — | 1 | 1 | |||||||||||||||||||
| Adjusted net income attributable to partners | 44 | $ | 20 | 14 | 106 | $ | 78 | 61 | |||||||||||||||||
| Maintenance capital expenditures, net of reimbursable projects | (3 | ) | (4 | ) | (10 | ) | (8 | ) | |||||||||||||||||
| Distributions from unconsolidated affiliates, net of earnings | 3 | 1 | 6 | 1 | |||||||||||||||||||||
| Depreciation and amortization, net of noncontrolling interests | 21 | 9 | 40 | 34 | |||||||||||||||||||||
| Impact of minimum volume receipt for throughput commitment | 2 | 2 | 4 | 3 | |||||||||||||||||||||
| Discontinued construction projects | — | — | 4 | — | |||||||||||||||||||||
| Adjustment to remove impact of pooling | — | — | (6 | ) | (17 | ) | |||||||||||||||||||
| Other | 1 | — | 1 | 3 | |||||||||||||||||||||
Distributable cash flow(1) | $ | 68 | $ | 22 | $ | 145 | $ | 77 | |||||||||||||||||
| Adjusted net income attributable to partners | $ | 44 | $ | 20 | $ | 14 | $ | 106 | $ | 78 | $ | 61 | |||||||||||||
| Adjusted net income attributable to predecessor operations | — | (6 | ) | — | (6 | ) | (20 | ) | (3 | ) | |||||||||||||||
| Adjusted general partner's interest in net income | (16 | ) | (10 | ) | (10 | ) | (31 | ) | (18 | ) | (18 | ) | |||||||||||||
| Adjusted net income allocable to limited partners | $ | 28 | $ | 4 | $ | 4 | $ | 69 | $ | 40 | $ | 40 | |||||||||||||
| Adjusted net income per limited partner unit - basic and diluted | $ | 0.36 | $ | 0.08 | $ | 0.08 | $ | 0.97 | $ | 0.81 | $ | 0.81 | |||||||||||||
| Net cash provided by operating activities | $ | 123 | $ | 3 | $ | 11 | $ | 270 | $ | 47 | $ | 72 | |||||||||||||
| Interest expense | 14 | 11 | 11 | 26 | 24 | 24 | |||||||||||||||||||
| Distributions from unconsolidated affiliates, net of earnings | (3 | ) | — | (1 | ) | (6 | ) | — | (1 | ) | |||||||||||||||
| Net changes in operating assets and liabilities | 11 | 99 | 80 | (54 | ) | 127 | 68 | ||||||||||||||||||
| Net income attributable to noncontrolling interests, net of depreciation and income tax | (6 | ) | (4 | ) | (1 | ) | (10 | ) | (10 | ) | (2 | ) | |||||||||||||
| Discontinued construction projects | — | — | — | (4 | ) | — | — | ||||||||||||||||||
| Non-cash commodity derivative mark-to-market | (58 | ) | (65 | ) | (65 | ) | (48 | ) | (42 | ) | (42 | ) | |||||||||||||
| Other, net | (2 | ) | — | — | (1 | ) | — | — | |||||||||||||||||
| Adjusted EBITDA | $ | 79 | $ | 44 | $ | 35 | $ | 173 | $ | 146 | $ | 119 | |||||||||||||
| Interest expense, net of derivative mark-to-market and other | (14 | ) | (11 | ) | (26 | ) | (20 | ) | |||||||||||||||||
| Maintenance capital expenditures, net of reimbursable projects | (3 | ) | (4 | ) | (10 | ) | (8 | ) | |||||||||||||||||
| Distributions from unconsolidated affiliates, net of earnings | 3 | 1 | 6 | 1 | |||||||||||||||||||||
| Adjustment to remove impact of pooling | — | — | (6 | ) | (17 | ) | |||||||||||||||||||
| Discontinued construction projects | — | — | 4 | — | |||||||||||||||||||||
| Other | 3 | 1 | 4 | 2 | |||||||||||||||||||||
Distributable cash flow(1) | $ | 68 | $ | 22 | $ | 145 | $ | 77 | |||||||||||||||||
| (1) | Distributable cash flow has not been calculated under the pooling method. |
12
DCP MIDSTREAM PARTNERS, LP
RECONCILIATION OF NON-GAAP FINANCIAL MEASURES
SEGMENT FINANCIAL RESULTS AND OPERATING DATA
(Unaudited)
| Three Months Ended | Six Months Ended | |||||||||||||||||||
| June 30, | June 30, | |||||||||||||||||||
| 2013 | As Reported in 2012 | 2013 | As Reported in 2012 | |||||||||||||||||
| (Millions, except as indicated) | ||||||||||||||||||||
| Reconciliation of Non-GAAP Financial Measures: | ||||||||||||||||||||
| Distributable cash flow | $ | 68 | $ | 22 | $ | 145 | $ | 77 | ||||||||||||
| Distributions declared | $ | 72 | $ | 49 | $ | 141 | $ | 92 | ||||||||||||
| Distribution coverage ratio - declared | 0.94 | x | 0.44 | x | 1.03 | x | 0.84 | x | ||||||||||||
| Distributable cash flow | $ | 68 | $ | 22 | $ | 145 | $ | 77 | ||||||||||||
| Distributions paid | $ | 69 | $ | 43 | $ | 123 | $ | 80 | ||||||||||||
| Distribution coverage ratio - paid | 0.99 | x | 0.51 | x | 1.18 | x | 0.97 | x | ||||||||||||
| Three Months Ended | Six Months Ended | ||||||||||||||||||||||||
| June 30, | June 30, | ||||||||||||||||||||||||
| 2013 | 2012 | As Reported in 2012 | 2013 | 2012 | As Reported in 2012 | ||||||||||||||||||||
| (Millions, except per unit amounts) | |||||||||||||||||||||||||
| Natural Gas Services Segment: | |||||||||||||||||||||||||
| Financial results: | |||||||||||||||||||||||||
| Segment net income attributable to partners | $ | 111 | $ | 106 | $ | 94 | $ | 150 | $ | 146 | $ | 116 | |||||||||||||
| Non-cash commodity derivative mark-to-market | (58 | ) | (49 | ) | (49 | ) | (49 | ) | (26 | ) | (26 | ) | |||||||||||||
| Depreciation and amortization expense | 21 | 14 | 8 | 39 | 45 | 30 | |||||||||||||||||||
| Noncontrolling interests on depreciation and income tax | (2 | ) | (2 | ) | — | (3 | ) | (4 | ) | (1 | ) | ||||||||||||||
| Adjusted segment EBITDA | $ | 72 | $ | 69 | $ | 53 | $ | 137 | $ | 161 | $ | 119 | |||||||||||||
| Operating and financial data: | |||||||||||||||||||||||||
| Natural gas throughput (MMcf/d) | 2,264 | 2,216 | 1,607 | 2,285 | 2,250 | 1,644 | |||||||||||||||||||
| NGL gross production (Bbls/d) | 112,785 | 105,282 | 62,771 | 113,446 | 105,709 | 62,978 | |||||||||||||||||||
| Operating and maintenance expense | $ | 43 | $ | 42 | $ | 23 | $ | 81 | $ | 77 | $ | 41 | |||||||||||||
| NGL Logistics Segment: | |||||||||||||||||||||||||
| Financial results: | |||||||||||||||||||||||||
| Segment net income attributable to partners | $ | 20 | $ | 10 | $ | 10 | $ | 42 | $ | 20 | $ | 20 | |||||||||||||
| Depreciation and amortization expense | 2 | 1 | 1 | 3 | 3 | 3 | |||||||||||||||||||
| Adjusted segment EBITDA | $ | 22 | $ | 11 | $ | 11 | $ | 45 | $ | 23 | $ | 23 | |||||||||||||
| Operating and financial data: | |||||||||||||||||||||||||
| NGL pipelines throughput (Bbls/d) | 93,306 | 72,786 | 72,786 | 88,800 | 77,740 | 77,740 | |||||||||||||||||||
| Operating and maintenance expense | $ | 4 | $ | 4 | $ | 4 | $ | 8 | $ | 8 | $ | 8 | |||||||||||||
| Wholesale Propane Logistics Segment: | |||||||||||||||||||||||||
| Financial results: | |||||||||||||||||||||||||
| Segment net income (loss) attributable to partners | $ | 1 | $ | (3 | ) | $ | (3 | ) | $ | 21 | $ | 14 | $ | 14 | |||||||||||
| Non-cash commodity derivative mark-to-market | — | (16 | ) | (16 | ) | 1 | (16 | ) | (16 | ) | |||||||||||||||
| Depreciation and amortization expense | — | — | — | 1 | 1 | 1 | |||||||||||||||||||
| Adjusted segment EBITDA | $ | 1 | $ | (19 | ) | $ | (19 | ) | $ | 23 | $ | (1 | ) | $ | (1 | ) | |||||||||
| Operating and financial data: | |||||||||||||||||||||||||
| Propane sales volume (Bbls/d) | 12,286 | 11,641 | 11,641 | 23,024 | 23,010 | 23,010 | |||||||||||||||||||
| Operating and maintenance expense | $ | 4 | $ | 4 | $ | 4 | $ | 7 | $ | 7 | $ | 7 | |||||||||||||
13
DCP MIDSTREAM PARTNERS, LP
RECONCILIATION OF NON-GAAP FINANCIAL MEASURES
(Unaudited)
| As Reported in Q312 | As Reported in Q412 | Q113 | Q213 | Twelve months ended June 30, 2013 (As Originally Reported) | |||||||||||||||||
| (Millions, except as indicated) | |||||||||||||||||||||
| Net income attributable to partners | $ | 1 | $ | 64 | $ | 52 | $ | 102 | $ | 219 | |||||||||||
| Maintenance capital expenditures, net of reimbursable projects | (4 | ) | (6 | ) | (7 | ) | (3 | ) | (20 | ) | |||||||||||
| Depreciation and amortization expense, net of noncontrolling interests | 15 | 14 | 19 | 21 | 69 | ||||||||||||||||
| Non-cash commodity derivative mark-to-market | 23 | (2 | ) | 10 | (58 | ) | (27 | ) | |||||||||||||
| Distributions from unconsolidated affiliates, net of earnings | (1 | ) | 1 | 3 | 3 | 6 | |||||||||||||||
| Impact of minimum volume receipt for throughput commitment | 2 | (6 | ) | 2 | 2 | — | |||||||||||||||
| Discontinued construction projects | — | — | 4 | — | 4 | ||||||||||||||||
| Adjustment to remove impact of pooling | — | — | (6 | ) | — | (6 | ) | ||||||||||||||
| Other | (1 | ) | 3 | — | 1 | 3 | |||||||||||||||
| Distributable cash flow | $ | 35 | $ | 68 | $ | 77 | $ | 68 | $ | 248 | |||||||||||
| Distributions declared | $ | 53 | $ | 54 | $ | 69 | $ | 72 | $ | 248 | |||||||||||
| Distribution coverage ratio - declared | 0.67x | 1.25x | 1.12x | 0.94x | 1.00x | ||||||||||||||||
| Distributable cash flow | $ | 35 | $ | 68 | $ | 77 | $ | 68 | $ | 248 | |||||||||||
| Distributions paid | $ | 49 | $ | 53 | $ | 54 | $ | 69 | $ | 225 | |||||||||||
| Distribution coverage ratio - paid | 0.72x | 1.29x | 1.43x | 0.99x | 1.10x | ||||||||||||||||
14