DCP Midstream, LP Reports Second Quarter 2017 Results

DENVER, Aug. 07, 2017 (GLOBE NEWSWIRE) -- DCP Midstream, LP (NYSE:DCP), or the Partnership, today reported financial results for the three and six months ended June 30, 2017.

SUMMARY

• Net income attributable to partners was $88 million and $189 million for the three and six months ended June 30, 2017, or $0.33 and $0.74 per basic and diluted limited partner unit, respectively.
• The Partnership reaffirmed its 2017 forecasted adjusted EBITDA and forecasted distributable cash flow guidance and tightened its outlook to between the low and midpoint of the guidance ranges to reflect the current commodity outlook for the second half of the year.
• Strong July performance, with record volumes in the DJ Basin, volume growth in the Eagle Ford and NGL pipelines and continued improvement in the Permian, setting the pace for improved second half of 2017.
• The Partnership is executing its 2017 and 2018 Sand Hills expansions from 280 thousand barrels per day (MBpd) to 450 MBpd, adding 60 plus percent capacity to Sand Hills by the third quarter 2018.
• The Partnership approved its eleventh plant in the DJ Basin, the 200 million cubic feet per day (MMcf/d) O'Connor 2 plant, and together with the 200 MMcf/d Mewbourn 3 plant that is under construction, will add 400 MMcf/d of processing capacity, up 45 plus percent, to approximately 1.2 billion cubic feet per day (Bcf/d).
• In June 2017, the Partnership sold its non-core Douglas system for approximately $129 million and recorded a gain of approximately $34 million. The assets were sold for a double-digit EBITDA multiple and the proceeds will be used to fund the Partnership's strategic lower multiple organic growth projects in its key basins.

SECOND QUARTER 2017 SUMMARY FINANCIAL RESULTS

FINANCIAL HIGHLIGHTS

• Adjusted EBITDA was $216 million and $461 million for the three and six months ended June 30, 2017, respectively.
• Distributable cash flow was $119 million and $280 million for the three and six months ended June 30, 2017, respectively.
• Distribution coverage ratio was 0.89 times and 1.04 times for the three and six months ended June 30, 2017, respectively, as adjusted for lower declared incentive distribution (IDR) rights payments to the Partnership's general partner of $20 million during each of the first and second quarters of 2017. See Distributions and IDR Giveback section for additional details.

CEO'S PERSPECTIVE

“The lower second quarter results were in line with our expectations and we are reaffirming our 2017 guidance. With strong July performance, we are off to an excellent start to the second half of the year," said Wouter van Kempen, chairman, CEO and president of the Partnership. "Based on the volume outlook in our key basins we are advancing the addition of two new processing plants in the DJ Basin, adding 400 million cubic feet per day of capacity. In addition, we are well underway with our 2017 and 2018 Sand Hills expansions to 450 thousand barrels per day in the Permian, adding over 60 percent of additional capacity."

ADVANCING THE PARTNERSHIP'S DISCIPLINED GROWTH STRATEGY IN ITS STRONGEST BASINS

Permian Growth Projects

Sand Hills

The following 2017 and 2018 Sand Hills expansions are expected to increase current capacity by 60+ percent to meet growing market demand.

• The 2017 Sand Hills natural gas liquids (NGL) pipeline capacity expansion to 365 MBpd to meet growth in the Permian Basin is underway and expected to be in service in the fourth quarter of 2017, for an estimated cost of $70 million, net to the Partnership's two-thirds interest. 
• The 2018 Sand Hills expansion announced in May 2017 is progressing and is expected to further increase capacity by 85 MBpd to approximately 450 MBpd via partial looping of the pipeline and the addition of new pump stations. This expansion is expected to be in service in the third quarter of 2018, for an estimated cost of $300 million, net to the Partnership's two-thirds interest.

Gulf Coast Express

• The non-binding open season for the proposed Gulf Coast Express Pipeline Project closed on April 20, 2017, with bids exceeding the capacity offered. Kinder Morgan (KMI) and the Partnership continue to work with prospective shippers to obtain firm commitments. The proposed mostly 42-inch pipeline would transport over 1.8 Bcf/d of natural gas approximately 430 miles from the Waha area to Agua Dulce, Texas, providing an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. The pipeline is expected to be in service in the second half of 2019, pending final shipper commitments.

DJ Basin Growth Projects

Increasing processing and bypass capacity in the DJ Basin by over 45 percent to approximately 1.2 Bcf/d by 2019. To support expansion of natural gas gathering and processing capacity in the DJ Basin, the Partnership and several key producers have entered into agreements whereby certain producers will provide long-term minimum volume commitments with minimum fees.

• The Partnership approved the 200 MMcf/d O'Connor 2 plant, its eleventh plant in the DJ Basin. The O'Connor 2 plant and associated gathering infrastructure is expected to be in service in 2019 for an estimated cost of $350 million to $400 million.
• The Partnership has started construction of the 200 MMcf/d Mewbourn 3 plant and additional compression and gathering infrastructure. The plant and gathering infrastructure are expected to be in service in the fourth quarter of 2018 for an estimated cost of $395 million.
• The Partnership increased capacity in the DJ Basin by up to 40 MMcf/d in the second quarter of 2017 by placing additional field compression and plant bypass infrastructure in service.

2017 OUTLOOK

The Partnership reaffirmed its 2017 forecasted adjusted EBITDA and distributable cash flow guidance of  $940 to $1,110 million and  $545 to $670 million, respectively, and tightened its outlook to between the low and midpoint of these ranges to reflect the current commodity outlook for the second half of the year. The Partnership expects its distribution coverage ratio to be approximately 1.0 times, which may include IDR givebacks of up to $100 million, providing a hedge against lower commodity prices. Maintenance capital expenditures are expected to be at the lower end of the Partnership's $100 million to $145 million 2017 forecast range and growth capital expenditures are expected to be at the higher end of its $325 million to $375 million 2017 forecast range.

DISTRIBUTIONS AND IDR GIVEBACK

On July 24, 2017, the Partnership announced a quarterly distribution of $0.78 per limited partner unit. This distribution remains unchanged from the previous quarter.

The Partnership generated distributable cash flow of $119 million and $280 million for the three and six months ended June 30, 2017, respectively. Total distributions declared net of IDR givebacks resulted in a distribution coverage ratio of 0.89 times for the second quarter 2017 and 1.04 times for the six months ended June 30, 2017.  

As part of the Transaction, Phillips 66 and Enbridge, Inc (Owners) agreed, if required, to provide a reduction to incentive distributions payable to the Partnership's general partner under the partnership agreement of up to $100 million annually through 2019 to target an approximate 1.0 times annual distribution coverage ratio which provides downside protection for limited partners.

Under the terms of the Partnership's amended partnership agreement, the amount of incentive distributions paid to the general partner will be evaluated by the general partner on both a quarterly and annual basis and may be reduced each quarter by an amount determined by the general partner (the "IDR giveback"). If no determination is made by the general partner, the quarterly IDR giveback will be $20 million. The IDR giveback of up to $100 million annually, will be subject to a true-up at the end of the year by taking the total distributable cash flow (as adjusted under the amended partnership agreement) less the total annual distribution payable to unitholders, adjusted to target an approximate 1.0 times distribution coverage ratio. In accordance with the amended partnership agreement, distributions declared were $134 million and $269 million for the three and six months ended June 30, 2017, respectively, reflecting $20 million and $40 million of IDR givebacks for the respective periods.

SECOND QUARTER 2017 OPERATING RESULTS BY BUSINESS SEGMENT

Gathering and Processing

Gathering and Processing Segment net income attributable to partners for the three months ended June 30, 2017 and 2016 was $141 million and $56 million, respectively.

Adjusted segment EBITDA decreased to $179 million for the three months ended June 30, 2017, from $183 million for the three months ended June 30, 2016, reflecting lower volumes across the Partnership's South, Midcontinent and Permian regions primarily due to reduced drilling activity in prior periods and the disposition of its Northern Louisiana system in June 2016. Lower results also reflected higher costs associated with increased asset reliability and planned maintenance and spending associated with anticipated volume growth. These decreases were partially offset by higher commodity prices, net of hedges, stronger performance from the Partnership's DJ Basin system in its North region, which benefited from higher margins and NGL recoveries, and higher margins from contract realignment efforts in the Permian and Midcontinent regions.

Earnings from the Partnership's Discovery investment included an $8 million increase due to the accelerated recognition of deferred revenue associated with lower producer volume projections. The increase to earnings did not impact the second quarter distribution. The reduction to the producer volume projections is anticipated to negatively impact future earnings and distributions from Discovery.

Logistics and Marketing

Logistics and Marketing Segment net income attributable to partners for the three months ended June 30, 2017 and 2016 was $92 million and $76 million, respectively.

Adjusted segment EBITDA decreased to $103 million for the three months ended June 30, 2017, from $106 million for the three months ended June 30, 2016, reflecting lower gas marketing settlements related to the Partnership's commodity derivative program around its natural gas storage assets, higher costs associated with planned maintenance and lower unit margins in its wholesale propane business. These decreases were partially offset by higher distributions primarily due to the 2016 expansion and volume ramp on Sand Hills associated with Permian growth. 

Other

Corporate operating and maintenance and general and administrative expenses for the three months ended June 30, 2017 were higher compared to the three months ended June 30, 2016 primarily as a result of investment in technology and innovation to drive greater productivity, reliability and efficiency. Interest expense for the three months ended June 30, 2017 decreased compared to 2016 as a result of lower average outstanding debt balances.  The three months ended June 30, 2016 included restructuring costs of $8 million associated with a reduction in force that occurred in April 2016.

CAPITALIZATION, LIQUIDITY AND FINANCING

At June 30, 2017, the Partnership had $5,225 million of total principal long-term debt outstanding, including $500 million of current maturities. The total debt outstanding includes $550 million of junior subordinated notes which are excluded from debt under the Partnership's credit facility leverage ratio calculation.

The Partnership has an approximately $1.4 billion senior unsecured revolving credit agreement that matures on May 1, 2019, or the Credit Agreement. The Credit Agreement is used for working capital requirements and other general partnership purposes including growth and acquisitions. As of June 30, 2017, total available revolver capacity was $1,373 million net of $25 million of letters of credit. The financial covenants set forth in the Credit Agreement limit the Partnership's ability to incur incremental debt by $1,187 million as of June 30, 2017. The Partnership's leverage ratio pursuant to its credit facility for the quarter ended June 30, 2017, was approximately 4.5 times. The effective interest rate on the Partnership's overall debt position, as of June 30, 2017, was 5.5% percent. As of June 30, 2017, the Partnership had cash of $251 million.

During the second quarter of 2017, the Partnership did not issue any equity to the public. 

CAPITAL EXPENDITURES AND INVESTMENTS

During the three and six months ended June 30, 2017, the Partnership had expansion capital expenditures and equity investments totaling $99 million and $154 million, respectively, and maintenance capital expenditures totaling $29 million and $44 million, respectively.

COMMODITY DERIVATIVE ACTIVITY

For the three and six months ended June 30, 2017, commodity derivative activity and total revenues included non-cash unrealized gains of $24 million and $60 million, respectively, and non-cash losses of $44 million and $89 million for the three and six months ended June 30, 2016, respectively. Net hedge cash settlements for the three and six months ended June 30, 2017, were payments of $2 million and $7 million, respectively. Net hedge cash settlements for the three and six months ended June 30, 2016, were receipts of $21 million and $84 million respectively.

The objective of the Partnership's commodity risk management program is to protect downside risk in its distributable cash flow. The Partnership also manages commodity price risk related to its natural gas storage and pipeline assets through its commodity derivative program. The commercial activities related to the Partnership's natural gas storage and pipeline assets primarily consist of locking in spreads associated with the purchase and sale of gas. The Partnership utilizes mark-to-market accounting treatment for its 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 the Partnership's 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 the Partnership's physical commodity sales are realized or when the Partnership rebalances its portfolio. Non-cash gains or losses associated with the mark-to-market accounting treatment of the Partnership's commodity derivative instruments do not affect its distributable cash flow.

EARNINGS CALL

The Partnership will host a conference call webcast today, August 7, at 2:00 p.m. ET, to discuss its second quarter 2017 results. The live audio webcast of the conference call and presentation slides can be accessed through the Investors section on the DCP website at www.dcpmidstream.com and the conference call can be accessed by dialing (844) 233-0113 in the United States or (574) 990-1008 outside the United States. The conference confirmation number is 51044925. A replay of the audio webcast will also be available by accessing the Investors section on the DCP website at www.dcpmidstream.com.

NON-GAAP FINANCIAL INFORMATION

This press release and the accompanying financial schedules include the following non-GAAP financial measures: adjusted EBITDA, distributable cash flow, adjusted segment EBITDA, forecasted adjusted EBITDA and forecasted distributable cash flow. 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 the Partnership may not be comparable to similarly titled measures of other companies because they may not calculate their measures in the same manner.

The Partnership defines adjusted EBITDA as net income or loss attributable to partners adjusted for (i) distributions from unconsolidated affiliates, net of earnings (ii) depreciation and amortization expense, (iii) net interest expense, (iv) noncontrolling interest in depreciation and income tax expense, (v) unrealized gains and losses from commodity derivatives, (vi) income tax expense or benefit, (vii) impairment expense and (viii) certain other non-cash items. Adjusted EBITDA further excludes items of income or loss that we characterize as unrepresentative of the Partnership's ongoing operations. Management believes these measures provide investors meaningful insight into results from ongoing operations.

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.

Adjusted EBITDA is used as a supplemental liquidity and performance measure and adjusted segment EBITDA is used as a 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 pay maintenance capital expenditures.

The Partnership defines adjusted segment EBITDA for each segment as segment net income or loss attributable to partners adjusted for (i) distributions from unconsolidated affiliates, net of earnings (ii) depreciation and amortization expense, (iii) noncontrolling interest in depreciation and income tax expense, (iv) unrealized gains and losses from commodity derivatives, (v) impairment expense and (vi) certain other non-cash items for that segment.

The Partnership defines distributable cash flow as adjusted EBITDA less maintenance capital expenditures, interest expense, the impact of minimum volume receipt for throughput commitments and certain other items.

Maintenance capital expenditures are cash expenditures made to maintain the Partnership's cash flows, operating capacity or earnings capacity. These expenditures add on to or improve capital assets owned, including certain system integrity, compliance and safety improvements. Maintenance capital expenditures also include certain well connects, and may include the acquisition or construction of new capital assets. 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. The Partnership compares the distributable cash flow it generates to the cash distributions it expects to pay and have paid to its partners. Using this metric, the Partnership computes its distribution coverage ratio. 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.

ABOUT DCP MIDSTREAM, LP

DCP Midstream, LP (NYSE:DCP) is a midstream master limited partnership, with a diversified portfolio of assets, engaged in the business of gathering, compressing, treating, processing, transporting, storing and selling natural gas; producing, fractionating, transporting, storing and selling NGLs and recovering and selling condensate. DCP owns and operates more than 60 plants and 63,000 miles of natural gas and natural gas liquids pipelines, with operations in 17 states across major producing regions and leads the midstream segment as one of the largest natural gas liquids producers and marketers and one of the largest natural gas processors in the U.S. Denver, Colorado based DCP is managed by its general partner, DCP Midstream GP, LP, which is managed by its general partner, DCP Midstream GP, LLC, which is 100% owned by DCP Midstream, LLC. DCP Midstream, LLC is a joint venture between Enbridge and Phillips 66. For more information, visit the DCP Midstream, LP website at www.dcpmidstream.com.

CAUTIONARY STATEMENTS

This press release may contain or incorporate by reference forward-looking statements as defined under the federal securities laws regarding DCP Midstream, 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 "Risk Factors" section of the Partnership's most recently filed annual report and subsequently filed quarterly reports 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.

Investors or Analysts:
Irene Lofland, 303-605-1822