TRC
Windsor, United States
TRC
Windsor, United States

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HOUSTON, Feb. 15, 2017 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE:TRGP) (“TRC”, the “Company” or “Targa”) today reported fourth quarter and full year 2016 results. Fourth quarter 2016 net income (loss) attributable to Targa Resources Corp. was ($150.8) million compared to $27.0 million for the fourth quarter of 2015. For the full year 2016, net income (loss) attributable to Targa Resources Corp. was ($187.3) million compared to $58.3 million for 2015. The Company reported earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“Adjusted EBITDA”) of $297.6 million for the fourth quarter of 2016 compared to $326.0 million for the fourth quarter of 2015. For the full year 2016, Adjusted EBITDA was $1,064.9 million compared to $1,191.7 million for 2015 (see the section of this release entitled “Targa Resources Corp. - Non-GAAP Financial Measures” for a discussion of Adjusted EBITDA, distributable cash flow, gross margin and operating margin, and reconciliations of such measures to their most directly comparable financial measures calculated and presented in accordance with U.S. generally accepted accounting principles (“GAAP”)). “2016 was a successful year for Targa as we were able to improve our balance sheet and asset position in a volatile period for our industry,” said Joe Bob Perkins, Chief Executive Officer of the Company.  “We recently announced the highly strategic acquisition of additional midstream assets in the Delaware and Midland Basins, where we are well-positioned to benefit from continued producer activity. With a healthy balance sheet and a diverse set of assets poised to capture increasing industry activity, we are well positioned looking out at the balance of 2017 and beyond.” On January 19, 2017, TRC declared a quarterly dividend of $0.91 per share of its common stock for the three months ended December 31, 2016, or $3.64 per share on an annualized basis, unchanged from the previous quarter’s dividend. Total cash dividends of approximately $176.5 million will be paid on February 15, 2017 on all outstanding shares of common stock to holders of record as of the close of business on February 1, 2017. Also on January 19, 2017, TRC declared a quarterly cash dividend of $23.75 per share of Series A Preferred Stock.  Total cash dividends of approximately $22.9 million were paid on February 14, 2017 on all outstanding shares of Series A Preferred Stock to holders of record as of the close of business on February 1, 2017. The Company reported distributable cash flow for the fourth quarter of 2016 of $246.2 million compared to total common dividends to be paid of $176.5 million and total Series A Preferred Stock dividends of $22.9 million, resulting in dividend coverage in excess of 1.2x with respect to the fourth quarter of 2016. For the full year 2016, distributable cash flow of $762.4 million resulted in approximately 1.1x dividend coverage on the common and Series A Stock dividends paid with respect to 2016. Targa’s total consolidated debt as of December 31, 2016 was $4,881.0 million including $275.0 million outstanding under TRC’s $670.0 million senior secured revolving credit facility due 2020 and $157.8 million, net of unamortized discounts, outstanding on the Company’s senior secured term loan due 2022. The consolidated debt also includes $4,452.0 million of Targa Resource Partners LP (“TRP” or “the Partnership”) debt, net of $30.3 million of debt issuance costs, including $150.0 million outstanding under TRP’s $1.6 billion senior secured revolving credit facility due 2020, $275.0 million outstanding under TRP’s accounts receivable securitization facility and $4,057.3 million of TRP senior notes, net of unamortized discounts and premiums. As of December 31, 2016, TRC had available senior secured revolving credit facility capacity of $395.0 million. TRP had $150.0 million in borrowings outstanding under its $1.6 billion senior secured revolving credit facility and $13.2 million in outstanding letters of credit, resulting in available senior secured revolving credit facility capacity of $1,436.8 million at the Partnership. Total Targa consolidated liquidity as of December 31, 2016, including $73.5 million of cash, was approximately $1.9 billion. In October 2016, the Partnership issued $500.0 million of 5⅛% Senior Notes due February 2025 and $500.0 million of 5⅜% Senior Notes due February 2027 resulting in total net proceeds of approximately $992.4 million. The net proceeds from the offering along with borrowings under its senior secured revolving credit facility were used to fund concurrent tender offers for other series of senior notes, as described below. Concurrently with the October 2016 senior notes offering, the Partnership commenced tender offers (the “Tender Offers”) to purchase for cash, subject to certain conditions, its 5% Senior Notes due January 2018 (the “5% Notes”), 6⅝% Senior Notes due October 2020 (the “6⅝% Notes”) and 6⅞% Senior Notes due February 2021 (the “6⅞% Notes” and together with the 5% Notes and 6⅝% Notes, the “Tender Notes”). The total consideration for each series of Tender Notes included a premium for each $1,000 principal amount of notes that was tendered as of the early tender date of October 5, 2016. The Tender Offers were fully subscribed, and the Partnership accepted for purchase all Tender Notes that were validly tendered as of the early tender date. The results of the Tender Offers, which closed in October 2016, were (in millions): Subsequent to the closing of the Tender Offers, the Partnership issued notices of full redemption to the trustees and noteholders of the 6⅝% Notes and the 6⅞% Notes for the note balances remaining after the Tender Offers. In addition, the Partnership issued notice of full redemption to the trustees and noteholders of the 6⅝% Senior Notes of Targa Pipeline Partners LP (“TPL”) due October 2020 (the “6⅝% TPL Notes”). The redemption price for the 6⅝% Notes and the 6⅝% TPL Notes was 103.313% of the principal amount, while the redemption price for the 6⅞% Notes was 103.438% of the principal amount. The aggregate principal amount outstanding of all three series of notes totaling $146.2 million were redeemed on November 15, 2016 for a total redemption payment of $151.1 million, excluding accrued interest. In October 2016, the Partnership amended and restated its senior secured revolving credit facility to extend the maturity date from October 2017 to October 2020. The available commitments under the facility of $1.6 billion remained unchanged while the Partnership’s ability to request additional commitments increased from up to $300.0 million to up to $500.0 million. On January 22, 2017, Targa entered into definitive agreements to purchase 100% of the membership interests of Outrigger Delaware Operating, LLC, Outrigger Southern Delaware Operating, LLC (together “Outrigger Delaware”) and Outrigger Midland Operating, LLC (“Outrigger Midland” and together with “Outrigger Delaware”, “Outrigger Permian”) (the “Outrigger Permian Acquisition”). Targa will pay $475 million in cash at closing and $90 million within 90 days of closing. Subject to certain performance-linked measures and other conditions, additional cash of up to $935 million may be received by the sellers of Outrigger Permian in potential earn-out payments that may occur in 2018 and 2019. The potential earn-out payments will be based upon a multiple of realized gross margin from existing contracts. Targa currently expects to close the transaction during the first quarter of 2017, subject to customary regulatory approvals and closing conditions. Outrigger Delaware’s gas gathering and processing and crude gathering systems are located in Loving, Winkler and Ward counties. The operations are backed by producer dedications of more than 145,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 14 years. Outrigger Delaware’s assets include 70 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the Outrigger Delaware system. Outrigger Midland’s gas gathering and processing and crude gathering systems are located in Howard, Martin and Borden counties. The operations are backed by producer dedications of more than 105,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 12.5 years. Outrigger Midland currently has 10 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the Outrigger Midland system. Targa anticipates connecting Outrigger Delaware to its existing Sand Hills system and Outrigger Midland to its existing WestTX system during 2017, creating operational and capital synergies. On January 26, 2017, TRC completed a public offering of 9,200,000 shares of common stock (including the underwriters’ overallotment option) at a price of $57.65, providing net proceeds of $524.1 million.  Targa intends to use the net proceeds from this public offering to fund a portion of the $565 million initial purchase price of the Outrigger Permian Acquisition. Targa expects that the remaining portion of the purchase price and related fees and expenses will be funded with borrowings under the Partnership’s senior secured revolving credit facility or, subject to market conditions, proceeds from the issuance of private or public securities. Prior to funding the Outrigger Permian Acquisition, or if the acquisition is not completed, Targa may use the net proceeds from the equity offering for general corporate purposes, which may include, among other things, repayment of our indebtedness (including the Partnership’s indebtedness), acquisitions, capital expenditures, additions to working capital and redeeming or repurchasing some of our outstanding notes. Given the continued producer activity around its systems, Targa estimates that 2017 Field Gathering and Processing (“G&P”) natural gas inlet volumes will average at least 10% higher than 2016 Field G&P average natural gas inlet volumes. In the Permian Basin, Targa anticipates average G&P natural gas inlet volumes will increase by approximately 20% in 2017 compared to 2016.  The Permian guidance includes anticipated volumes from the acquisition of assets in the Delaware and Midland Basins announced on January 23, 2017, and subject to customary regulatory approvals and other closing conditions, Targa expects the acquisition will close during the first quarter. In SouthTX and the Badlands, Targa estimates 2017 average natural gas inlet volumes will be higher than average 2016 volumes, and Targa also expects higher average crude volumes in the Badlands year over year. These volumes increases will be partially offset by lower volumes in WestOK, SouthOK and North Texas. In the Downstream business, related to its LPG export business at Galena Park, Targa has approximately two-thirds of its current estimated export capacity of 7 million barrels per month contracted each year at attractive rates through 2022. Some years are slightly higher and some years are slightly lower than two-thirds, but two-thirds is representative of the significant percentage of current LPG export capacity contracted in each year. In support of the growth Targa is seeing in its G&P business and the additional growth opportunities upstream activity is creating in its Downstream business, Targa expects that 2017 net growth capital expenditures will be at least $700 million, based on currently announced projects and other identified spending. There are a number of other attractive G&P and Downstream projects under development, but not yet announced, that may require additional growth capex spending in 2017. Net maintenance capital expenditures for 2017 are estimated to be approximately $110 million. For full year 2017, Targa expects dividend coverage to exceed 1.0 times assuming a $3.64 per common share 2017 dividend. Inclusive of the January 23, 2017 acquisition in the Permian Basin, Targa estimates that it will not pay cash taxes for the next 5 years. Targa will host a conference call for investors and analysts at 10:00 a.m. Eastern time (9:00 a.m. Central time) on February 15, 2017 to discuss fourth quarter and full year 2016 results. The conference call can be accessed via webcast through the Events and Presentations section of Targa’s website at www.targaresources.com, by going directly to http://ir.targaresources.com/trc/events.cfm or by dialing 877-881-2598.  The conference ID number for the dial-in is 62528053. Please dial in ten minutes prior to the scheduled start time. A replay will be available approximately two hours following the completion of the webcast through the Investors section of the Company’s website. An updated investor presentation will also be available in the Events and Presentations section of the Company’s website following the completion of the conference call. (1) Gross margin, operating margin, adjusted EBITDA, and distributable cash flow are non-GAAP financial measures and are discussed under “Targa Resources Corp. – Non-GAAP Financial Measures.” (2) Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant, other than in Badlands, where it represents total wellhead gathered volume. (3) Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes. (4) These volume statistics are presented with the numerator as the total volume sold during the period and the denominator as the number of calendar days during the period. (5) Export volumes represent the quantity of NGL products delivered to third-party customers at our Galena Park Marine Terminal that are destined for international markets. (6) Includes the impact of intersegment eliminations. NM      Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful. The increase in commodity sales was primarily due to higher NGL and natural gas prices ($447.2 million), partially offset by lower NGL volumes ($32.7 million) and the impact of hedge settlements ($17.5 million). Fee-based and other revenues decreased primarily due to lower fractionation and export fees. The increase in product purchases reflects the same factors as commodity sales, which were the impact of the higher commodity prices, partially offset by lower NGL volumes. Operating margin was flat while gross margin increased slightly in 2016, which reflects increased Gathering and Processing segment margins, offset by decreased Logistics and Marketing segment margin results. Operating expenses increased compared to 2015 due to higher compensation, benefits and utilities expenses. See “—Review of Segment Performance” for additional information regarding changes in operating margin and gross margin on a segment basis. The decrease in depreciation and amortization expenses is primarily due to the $32.6 million charge in 2015 to reflect an impairment of certain gas processing facilities and associated gathering systems due to market conditions and processing spreads in Louisiana. In 2016, there were no impairments of property, plant and equipment or intangibles assets. General and administrative expenses increased primarily due to higher compensation and benefits, partially offset by lower professional services. The Company recognized an impairment of goodwill of $183.0 million during 2016 as compared with the $290.0 million provisional impairment of goodwill recorded during the fourth quarter of 2015, which was finalized in the first quarter of 2016 with an additional impairment of $24.0 million. These impairment charges relate to goodwill acquired in 2015 in connection with the Company’s acquisition of Atlas Energy LP (“ATLS”) and Atlas Pipeline Partners, LP (“APL”) (collectively, the “Atlas mergers”). Other operating (income) expense in 2016 increased as the Company reported net gains on sales of assets in 2015. Net interest expense increased primarily due to lower non-cash interest income related to the mandatorily redeemable preferred interest liability that is revalued quarterly at the estimated redemption value as of the reporting date. The estimated redemption value of the mandatorily redeemable preferred interests liability increased during 2016 as compared with a decrease in 2015. Other factors included lower capitalized interest due to decreased capital expenditures in 2016, partially offset by the impact of lower average outstanding borrowings during 2016. The decrease in equity earnings (loss) was due to lower operating results from Gulf Coast Fractionators LP (“GCF”). During 2016, the Company recorded a $69.6 million loss from financing activities that included the tender of certain senior notes of the Partnership, redemption of certain senior notes of the Partnership and the write-off of debt issuance costs associated with the amendment of the TRP revolving credit facility. In 2015, the Company incurred a net gain from financing activities of $3.5 million from the Partnership’s debt repurchases. The change in income tax (expense) benefit was primarily due to the impact of the TRC/TRP Merger, which eliminated the noncontrolling interest associated with the third-party TRP common unit holders for most of 2016. Income attributable to noncontrolling interests is not subject to income taxes in our financial statements.  Therefore, during most of 2016, we recorded income taxes on the majority of the pre-tax loss generated by TRP due to absence of the large noncontrolling interest in TRP. Net income (loss) attributable to noncontrolling interests was significantly lower for 2016 due to the absence of the third-party common noncontrolling interest that was acquired in the February 2016 TRC/TRP Merger described above. The impact of the TRP buy-in was most pronounced during the fourth quarter of both years because each included significant losses as a result of the Company’s annual goodwill impairment evaluations. The noncontrolling interest bore approximately 89% of the fourth quarter impairment loss in 2015 versus 0% in 2016. Preferred dividends in 2016 represent both cash dividends related to the March 2016 Series A Preferred Stock offering and non-cash deemed dividends for the accretion of the preferred discount related to a beneficial conversion feature. The increase in commodity sales was primarily due to the favorable impact of the inclusion of two additional months of TPL’s operations during 2016 ($270.1 million), partially offset by lower commodity prices ($53.7 million) and the impact of hedge settlements ($42.5 million). Additionally, fee-based and other revenues decreased primarily due to lower fractionation and export fees, partially offset by the impact of an additional two months of TPL’s fee revenue in 2016 ($40.9 million). The increase in product purchases was primarily due to the inclusion of two additional months of operations from TPL in 2016 ($137.5 million), partially offset by the impact of the lower commodity prices. The lower operating margin and gross margin in 2016 reflects decreased segment margin results for Logistics and Marketing, partially offset by increased Gathering and Processing segment margins. Operating expenses increased slightly compared to 2015 due to the inclusion of TPL’s operations for an additional two months in 2016, offset by a continued focused cost reduction effort throughout our operating areas. See “—Review of Segment Performance” for additional information regarding changes in operating margin and gross margin on a segment basis. The increase in depreciation and amortization expenses reflects an additional two months of TPL operations in 2016, growth investments from other system expansions including CBF Train 5, the Buffalo Plant, compressor stations and pipelines, and higher planned amortization of the Badlands intangible assets. Partially offsetting these factors was an additional $32.6 million charge to depreciation in 2015 to reflect an impairment of certain gas processing facilities and associated gathering systems in the Gathering and Processing segment due to market conditions and processing spreads in Louisiana. General and administrative expenses, which include TPL operations for an additional two months in 2016, increased primarily due to higher compensation and benefits, partially offset by lower property insurance premiums. The Company recognized impairments of goodwill totaling $207.0 million during 2016, as compared with the $290.0 million provisional impairment of goodwill recorded during the fourth quarter of 2015. Goodwill impairment recorded in 2016 includes $24.0 million recorded in the first quarter to finalize the 2015 provisional charge, as well as an additional $183.0 million associated with the Company’s annual impairment evaluation in the fourth quarter of 2016. These impairment charges relate to goodwill acquired in the 2015 Atlas mergers. Other operating (income) expense in 2016 includes the loss on decommissioning two storage wells at the Company’s Hattiesburg facility and an acid gas injection well at the Company’s Versado facility, whereas in 2015 the Company reported a net gain on sales of assets. Net interest expense increased primarily due to lower non-cash interest income related to the mandatorily redeemable preferred interests liability that is revalued quarterly at the estimated redemption value as of the reporting date. The estimated redemption value of the mandatorily redeemable preferred interests liability decreased in 2016 by a lesser amount than in 2015. Other factors included lower capitalized interest due to decreased capital expenditures in 2016, partially offset by the impact of lower average outstanding borrowings during 2016. The decrease in equity earnings (loss) was due to lower operating results from GCF and the inclusion of an additional two months of equity losses from the T2 Joint Ventures in 2016. During 2016, the Company recorded a $48.2 million loss from financing activities that included the tender of $1,138.3 million of certain senior notes of the Partnership, the repurchase of $559.2 million of certain senior notes of the Partnership in open market purchases, and the redemption of $146.2 million of certain senior notes of the Partnership. In 2015, the Company incurred a net loss from financing activities of $10.1 million from the partial repayments of the TRC senior secured term loan and the repurchase of certain senior notes of the Partnership. Other income (expense) in 2015 was primarily attributable to non-recurring transaction costs related to the Atlas mergers. The change in income tax (expense) benefit was primarily due to the decrease in income (loss) before income taxes and the impact of the TRC/TRP Merger, which eliminated the noncontrolling interest associated with the third-party TRP common unit holders for most of 2016. Income attributable to noncontrolling interests is not subject to income taxes in our financial statements.  Therefore, during most of 2016, we recorded income taxes on the majority of the pre-tax loss generated by TRP due to absence of the large noncontrolling interest in TRP. Despite similar amounts of net losses in 2016 and 2015,  net income (loss) attributable to noncontrolling interests was significantly lower for 2016 due to the February 2016 TRC/TRP Merger, which eliminated the noncontrolling interest associated with the third-party TRP common unit holders for most of 2016.  The impact of the TRP non-controlling common interest buy-in was most pronounced during the fourth quarter of both years which included significant losses as a result of our annual goodwill impairment evaluations. The noncontrolling interest bore approximately 89% of the fourth quarter impairment loss in 2015 and 0% in 2016. This reduction was partially offset by the impact of a full year of distributions in 2016 for the TRP's Preferred Units issued in October 2015. Preferred dividends in 2016 represent both cash dividends on Series A Preferred Stock and non-cash deemed dividends for the accretion of the preferred discount related to a beneficial conversion feature. The Series A Preferred Stock was issued on March 16, 2016. The following discussion of segment performance includes inter-segment activities. The Company views segment operating margin as an important performance measure of the core profitability of its operations. This measure is a key component of internal financial reporting and is reviewed for consistency and trend analysis. For a discussion of operating margin, see “Targa Resources Corp. - Non-GAAP Financial Measures - Operating Margin.” Segment operating financial results and operating statistics include the effects of intersegment transactions. These intersegment transactions have been eliminated from the consolidated presentation. For all operating statistics presented, the numerator is the total volume or sales during the applicable reporting period and the denominator is the number of calendar days during the applicable reporting period. The Company operates in two primary segments (previously referred to as divisions): (i) Gathering and Processing, previously disaggregated into two reportable segments—(a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing (also referred to as the Downstream Business), previously disaggregated into two reportable segments—(a) Logistics Assets and (b) Marketing and Distribution. Concurrent with the TRC/TRP Merger, management reevaluated the Company’s reportable segments and determined that its divisions are the appropriate level of disclosure for the Company’s reportable segments. The increase in activity within Field Gathering and Processing due to the Atlas mergers coupled with the decline in activity in the Gulf Coast region makes the disaggregation of Field Gathering and Processing and Coastal Gathering and Processing no longer warranted. Management also determined that further disaggregation of the Logistics and Marketing division is no longer appropriate due to the integrated nature of the operations within TRC’s Downstream Business and its leadership by a consolidated executive management team. The Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma and South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico. The following table provides summary data regarding results of operations of this segment for the periods indicated: (1) Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period, including the volumes related to plants acquired in the APL merger. (2) Plant natural gas inlet represents the Company’s undivided interest in the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant. (3) Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes. (4) Includes wellhead gathered volumes moved from Sand Hills via pipeline to SAOU for processing. (5) Operations acquired as part of the APL merger effective February 27, 2015. (6) Badlands natural gas inlet represents the total wellhead gathered volume. (7) Average realized prices exclude the impact of hedging activities presented in Other. Three Months Ended December 31, 2016 Compared to Three Months Ended December 31, 2015 The increase in gross margin was primarily due to higher commodity prices offset by lower throughput volumes. Total Field inlet volumes were down slightly, with increases at SAOU, WestTX, Versado and SouthTX offsetting decreases at the other areas. The inlet volume decrease for Coastal, which generates significantly lower margins than does Field, accounted for 90% of the overall inlet volume decrease. NGL production and NGL sales increased primarily due to increased plant recoveries due to additional ethane recovery and more efficient plant operations. Natural gas sales decreased due to lower inlet volumes and increased ethane recovery. Badlands natural gas and crude oil volumes decreased primarily due to the timing of producer well completion fracturing and associated shut-in of adjacent wells and to inclement weather. Excluding the impact of a one-time expense reduction settlement recorded in the fourth quarter of 2015, operating expenses for most areas were lower due to a continued focused cost reduction effort. The increase in gross margin was primarily due to the inclusion of the TPL volumes for all of 2016 and an increase in NGL prices partially offset by lower natural gas and condensate prices and lower inlet volumes in WestOK and on certain of the Company’s other systems. The plant inlet volume increase in SAOU was more than offset by reduced producer activity and volumes at Sand Hills (which also had operational issues), Versado and North Texas. Badlands natural gas volumes increased due to system expansions while crude oil volumes were essentially flat. Coastal plant inlet volumes decreased due to current market conditions and the decline of off-system volumes partially offset by additional higher GPM volumes. Excluding the impact of including operating expenses for TPL for an additional two months in 2016 and system expansions, operating expenses for most areas were lower due to a continued focused cost reduction effort. The table below provides a reconciliation between gross operating statistics and the actual reported operating statistics for the Field portion of the Gathering and Processing segment: (1) Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant. (2) Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes. (3) For these volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the  period. (4) Includes wellhead gathered volumes moved from Sand Hills to SAOU for processing. (5) Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in the Company’s reported financials. (6) Includes the Buffalo Plant that commenced commercial operations in April 2016. (7) Versado is a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials. Targa held a 63% interest in Versado until October 31, 2016, when it acquired the remaining 37% interest. (8) SouthTX includes the Silver Oak II plant, of which TPL has owned a 90% interest since January 2016, and prior to which TPL owned a 100% interest. Silver Oak II is owned by a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials. (9) SouthOK includes the Centrahoma joint venture, of which TPL owns 60%, and other plants which are owned 100% by TPL. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials. (10) Badlands natural gas inlet represents the total wellhead gathered volume. (1) Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant. (2) Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes. (3) For these volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the  period. (4) Includes wellhead gathered volumes moved from Sand Hills to SAOU for processing. (5) Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in the Company’s reported financials. (6) Includes the Buffalo Plant that commenced commercial operations in April 2016. (7) Versado is a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials. Targa held a 63% interest in Versado until October 31, 2016, when it acquired the remaining 37% interest. (8)  SouthTX includes the Silver Oak II plant, of which TPL has owned a 90% interest since January 2016, and prior to which TPL owned a 100% interest. Silver Oak II is owned by a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials. (9) SouthOK includes the Centrahoma joint venture, of which TPL owns 60%, and other plants which are owned 100% by TPL. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials. (10) Badlands natural gas inlet represents the total wellhead gathered volume. The Logistics and Marketing segment includes all the activities necessary to convert mixed NGLs into NGL products and provides certain value added services such as storing, terminaling, distributing and marketing of NGLs, the storage and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of Targa’s other businesses including services to LPG exporters. It also includes certain natural gas supply and marketing activities in support of the Company’s other operations, as well as transporting natural gas and NGLs. Logistics and Marketing operations are generally connected to and supplied in part by the Company’s Gathering and Processing segments and are predominantly located in Mont Belvieu and Galena Park, Texas, Lake Charles, Louisiana and Tacoma, Washington. The following table provides summary data regarding results of operations of this segment for the periods indicated: (1) Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period. (2) Fractionation and treating contracts include pricing terms composed of base fees and fuel and power components which vary with the cost of energy.  As such, the Logistics and Marketing segment results include effects of variable energy costs that impact both gross margin and operating expenses. (3) Fractionation volumes reflect those volumes delivered and settled under fractionation contracts. (4) Export volumes represent the quantity of NGL products delivered to third-party customers at Targa’s Galena Park Marine Terminal that are destined for international markets. Three Months Ended December 31, 2016 Compared to Three Months Ended December 31, 2015 Logistics and Marketing gross margin decreased due to lower LPG export margin, partially offset by higher marketing gains, higher fractionation margin, and higher treating volumes. LPG export margin decreased due to lower fees, partially offset by higher volumes.  Fractionation margin increased primarily due to higher fees and favorable system product gains, partially offset by lower supply volumes. Fractionation margin was partially impacted by the variable effects of fuel and power which are largely reflected in operating expenses (see footnote (2) above). Operating expenses increased primarily due to higher compensation and benefits, higher fuel and power and the startup of CBF Train 5, partially offset by lower ad valorem taxes as a result of an adjustment from forecasted to actual. Logistics and Marketing gross margin decreased primarily due to lower LPG export margin and the realization in 2015 of contract renegotiation fees related to the Company’s crude oil and condensate splitter project. Gross margin also decreased due to lower fractionation margin and lower terminaling and storage throughput, partially offset by higher NGL marketing gains. LPG export margin decreased due to lower fees. Fractionation margin decreased primarily due to lower supply volume and lower system product gains, partially offset by higher fees. Fractionation margin was partially impacted by the variable effects of fuel and power which are largely reflected in operating expenses (see footnote (2) above). Operating expenses were relatively flat. Higher compensation and benefits and higher ad valorem taxes associated with the start-up of CBF Train 5 were largely offset by lower fuel and power, and lower maintenance expense resulting from continued focused cost reductions. Other contains the results (including any hedge ineffectiveness) of commodity derivative activities included in operating margin and mark-to-market gain/losses related to derivative contracts that were not designated as cash flow hedges. The primary purpose of Targa’s commodity risk management activities is to mitigate a portion of the impact of commodity prices on its operating cash flow. The Company has hedged the commodity price associated with a portion of its expected (i) natural gas equity volumes and (ii) NGL and condensate equity volumes in its Gathering and Processing Operations that result from percent of proceeds or liquid processing arrangements by entering into derivative instruments. Because the Company is essentially forward-selling a portion of its plant equity volumes, these hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices. The following table provides a breakdown of the change in Other operating margin: (1) The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction. (2) Mark-to-market income (loss) associated with derivative contracts that are not designated as hedges for accounting purposes. (3) Ineffectiveness primarily relates to certain crude hedging contracts and certain acquired hedges of APL that do not qualify for hedge accounting. As part of the Atlas mergers, outstanding APL derivative contracts with a fair value of $102.1 million as of the acquisition date were novated to the Company and included in the acquisition date fair value of assets acquired. Derivative settlements of $26.6 million and $67.9 million related to these novated contracts were received during the years ended December 31, 2016 and December 31, 2015, respectively, and were reflected as a reduction of the acquisition date fair value of the APL derivative assets acquired with no effect on results of operations. Targa Resources Corp. is a leading provider of midstream services and is one of the largest independent midstream energy companies in North America. Targa owns, operates, acquires, and develops a diversified portfolio of complementary midstream energy assets. The Company is primarily engaged in the business of: gathering, compressing, treating, processing, and selling natural gas; storing, fractionating, treating, transporting, and selling NGLs and NGL products, including services to LPG exporters; gathering, storing, and terminaling crude oil; and storing, terminaling, and selling refined petroleum products. The principal executive offices of Targa are located at 1000 Louisiana, Suite 4300, Houston, TX 77002 and their telephone number is 713-584-1000.  For more information please go to www.targaresources.com. This press release includes the Company’s non-GAAP financial measures Adjusted EBITDA, distributable cash flow, gross margin and operating margin. The following tables provide reconciliations of these non-GAAP financial measures to their most directly comparable GAAP measures. The Company’s non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income, operating income, net cash flows provided by operating activities or any other GAAP measure of liquidity or financial performance. The Company defines Adjusted EBITDA as net income (loss) available to TRC before: interest; income taxes; depreciation and amortization; impairment of goodwill; gains or losses on debt repurchases, redemptions, amendments, exchanges and early debt extinguishments and asset disposals; risk management activities related to derivative instruments including the cash impact of hedges acquired in the APL merger; non-cash compensation on equity grants; transaction costs related to business acquisitions; the Splitter Agreement adjustment; net income attributable to TRP preferred limited partners; earnings/losses from unconsolidated affiliates net of distributions, distributions from preferred interests, change in contingent consideration and the noncontrolling interest portion of depreciation and amortization expenses. Adjusted EBITDA is used as a supplemental financial measure by the Company and by external users of the Company’s financial statements such as investors, commercial banks and others. The economic substance behind the Company’s use of Adjusted EBITDA is to measure the ability of the Company’s assets to generate cash sufficient to pay interest costs, support our indebtedness and pay dividends to the Company’s investors. Adjusted EBITDA is a non-GAAP financial measure. The GAAP measure most directly comparable to Adjusted EBITDA is net income (loss) attributable to TRC. Adjusted EBITDA should not be considered as an alternative to GAAP net income. Adjusted EBITDA has important limitations as an analytical tool. Investors should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies in the Company’s industry, the Company’s definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility. Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into our decision-making processes. The Company defines distributable cash flow as Adjusted EBITDA less distributions to TRP preferred limited partners, the Splitter Agreement adjustments, cash interest expense on debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs). This measure includes the impact of noncontrolling interests on the prior adjustment items. Distributable cash flow is a significant performance metric used by the Company and by external users of the Company’s financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by the Company (prior to the establishment of any retained cash reserves by our board of directors) to the cash dividends the Company expects to pay its shareholders. Using this metric, management and external users of the Company’s financial statements can quickly compute the coverage ratio of estimated cash flows to cash dividends. Distributable cash flow is also an important financial measure for the Company’s shareholders since it serves as an indicator of the Company’s success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not the Company is generating cash flow at a level that can sustain or support an increase in the Company’s quarterly dividend rates. Distributable cash flow is a non-GAAP financial measure. The GAAP measure most directly comparable to distributable cash flow is net income (loss) attributable to TRC. Distributable cash flow should not be considered as an alternative to GAAP net income (loss) available to common and preferred shareholders. It has important limitations as an analytical tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of the Company’s results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently by different companies in the Company’s industry, the Company’s definition of distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility. Management compensates for the limitations of distributable cash flow as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these insights into the Company’s decision-making processes. The following table presents a reconciliation of net income of the Company to Adjusted EBITDA and Distributable Cash Flow for the periods indicated: (1) The definition of Adjusted EBITDA was revised in 2015 to exclude earnings from unconsolidated investments net of distribution and transactions costs related to business acquisitions. (2) In Adjusted EBITDA, the amount reflects the annual cash payment received for the Splitter Agreement recognized over the four quarters following receipt. In distributable cash flow, the amounts reflect the annual cash payment in the period received less the amount recognized in Adjusted EBITDA. (3) Noncontrolling interest portion of depreciation and amortization expenses. (4) Excludes amortization of interest expense. (5) Includes an adjustment, reflecting the benefit from net operating loss carryback to 2015 and 2014, which is recognized over a period of six quarters beginning in Q3 2016. The Company defines gross margin as revenues less product purchases. It is impacted by volumes and commodity prices as well as by the Company’s contract mix and commodity hedging program. Gathering and Processing segment gross margin consists primarily of revenues from the sale of natural gas, condensate, crude oil and NGLs and fee revenues related to natural gas and crude oil gathering and services, less producer payments and other natural gas and crude oil purchases. The gross margin impacts of cash flow hedge settlements are reported in Other. The Company defines operating margin as gross margin less operating expenses. Operating margin is an important performance measure of the core profitability of its operations. Management reviews business segment gross margin and operating margin monthly as a core internal management process. The Company believes that investors benefit from having access to the same financial measures that management uses in evaluating its operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures by management and by external users of the Company’s financial statements, including investors and commercial banks, to assess: Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is net income. Gross margin and operating margin are not alternatives to GAAP net income and have important limitations as analytical tools. Investors should not consider gross margin and operating margin in isolation or as a substitute for analysis of the Company’s results as reported under GAAP. Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies in the Company’s industry, the Company’s definitions of gross margin and operating margin may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes. The following table presents a reconciliation of net income to operating margin and gross margin for the periods indicated: Certain statements in this release are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future, are forward-looking statements. These forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside the Company’s control, which could cause results to differ materially from those expected by management of the Company. Such risks and uncertainties include, but are not limited to, weather, political, economic and market conditions, including a decline in the price and market demand for natural gas, natural gas liquids and crude oil, the timing and success of business development efforts; and other uncertainties. These and other applicable uncertainties, factors and risks are described more fully in the Company’s filings with the Securities and Exchange Commission, including its Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. The Company does not undertake an obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. Contact investor relations by phone at (713) 584-1133.


HOUSTON, Feb. 15, 2017 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE:TRGP) (“TRC”, the “Company” or “Targa”) today reported fourth quarter and full year 2016 results. Fourth quarter 2016 net income (loss) attributable to Targa Resources Corp. was ($150.8) million compared to $27.0 million for the fourth quarter of 2015. For the full year 2016, net income (loss) attributable to Targa Resources Corp. was ($187.3) million compared to $58.3 million for 2015. The Company reported earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“Adjusted EBITDA”) of $297.6 million for the fourth quarter of 2016 compared to $326.0 million for the fourth quarter of 2015. For the full year 2016, Adjusted EBITDA was $1,064.9 million compared to $1,191.7 million for 2015 (see the section of this release entitled “Targa Resources Corp. - Non-GAAP Financial Measures” for a discussion of Adjusted EBITDA, distributable cash flow, gross margin and operating margin, and reconciliations of such measures to their most directly comparable financial measures calculated and presented in accordance with U.S. generally accepted accounting principles (“GAAP”)). “2016 was a successful year for Targa as we were able to improve our balance sheet and asset position in a volatile period for our industry,” said Joe Bob Perkins, Chief Executive Officer of the Company.  “We recently announced the highly strategic acquisition of additional midstream assets in the Delaware and Midland Basins, where we are well-positioned to benefit from continued producer activity. With a healthy balance sheet and a diverse set of assets poised to capture increasing industry activity, we are well positioned looking out at the balance of 2017 and beyond.” On January 19, 2017, TRC declared a quarterly dividend of $0.91 per share of its common stock for the three months ended December 31, 2016, or $3.64 per share on an annualized basis, unchanged from the previous quarter’s dividend. Total cash dividends of approximately $176.5 million will be paid on February 15, 2017 on all outstanding shares of common stock to holders of record as of the close of business on February 1, 2017. Also on January 19, 2017, TRC declared a quarterly cash dividend of $23.75 per share of Series A Preferred Stock.  Total cash dividends of approximately $22.9 million were paid on February 14, 2017 on all outstanding shares of Series A Preferred Stock to holders of record as of the close of business on February 1, 2017. The Company reported distributable cash flow for the fourth quarter of 2016 of $246.2 million compared to total common dividends to be paid of $176.5 million and total Series A Preferred Stock dividends of $22.9 million, resulting in dividend coverage in excess of 1.2x with respect to the fourth quarter of 2016. For the full year 2016, distributable cash flow of $762.4 million resulted in approximately 1.1x dividend coverage on the common and Series A Stock dividends paid with respect to 2016. Targa’s total consolidated debt as of December 31, 2016 was $4,881.0 million including $275.0 million outstanding under TRC’s $670.0 million senior secured revolving credit facility due 2020 and $157.8 million, net of unamortized discounts, outstanding on the Company’s senior secured term loan due 2022. The consolidated debt also includes $4,452.0 million of Targa Resource Partners LP (“TRP” or “the Partnership”) debt, net of $30.3 million of debt issuance costs, including $150.0 million outstanding under TRP’s $1.6 billion senior secured revolving credit facility due 2020, $275.0 million outstanding under TRP’s accounts receivable securitization facility and $4,057.3 million of TRP senior notes, net of unamortized discounts and premiums. As of December 31, 2016, TRC had available senior secured revolving credit facility capacity of $395.0 million. TRP had $150.0 million in borrowings outstanding under its $1.6 billion senior secured revolving credit facility and $13.2 million in outstanding letters of credit, resulting in available senior secured revolving credit facility capacity of $1,436.8 million at the Partnership. Total Targa consolidated liquidity as of December 31, 2016, including $73.5 million of cash, was approximately $1.9 billion. In October 2016, the Partnership issued $500.0 million of 5⅛% Senior Notes due February 2025 and $500.0 million of 5⅜% Senior Notes due February 2027 resulting in total net proceeds of approximately $992.4 million. The net proceeds from the offering along with borrowings under its senior secured revolving credit facility were used to fund concurrent tender offers for other series of senior notes, as described below. Concurrently with the October 2016 senior notes offering, the Partnership commenced tender offers (the “Tender Offers”) to purchase for cash, subject to certain conditions, its 5% Senior Notes due January 2018 (the “5% Notes”), 6⅝% Senior Notes due October 2020 (the “6⅝% Notes”) and 6⅞% Senior Notes due February 2021 (the “6⅞% Notes” and together with the 5% Notes and 6⅝% Notes, the “Tender Notes”). The total consideration for each series of Tender Notes included a premium for each $1,000 principal amount of notes that was tendered as of the early tender date of October 5, 2016. The Tender Offers were fully subscribed, and the Partnership accepted for purchase all Tender Notes that were validly tendered as of the early tender date. The results of the Tender Offers, which closed in October 2016, were (in millions): Subsequent to the closing of the Tender Offers, the Partnership issued notices of full redemption to the trustees and noteholders of the 6⅝% Notes and the 6⅞% Notes for the note balances remaining after the Tender Offers. In addition, the Partnership issued notice of full redemption to the trustees and noteholders of the 6⅝% Senior Notes of Targa Pipeline Partners LP (“TPL”) due October 2020 (the “6⅝% TPL Notes”). The redemption price for the 6⅝% Notes and the 6⅝% TPL Notes was 103.313% of the principal amount, while the redemption price for the 6⅞% Notes was 103.438% of the principal amount. The aggregate principal amount outstanding of all three series of notes totaling $146.2 million were redeemed on November 15, 2016 for a total redemption payment of $151.1 million, excluding accrued interest. In October 2016, the Partnership amended and restated its senior secured revolving credit facility to extend the maturity date from October 2017 to October 2020. The available commitments under the facility of $1.6 billion remained unchanged while the Partnership’s ability to request additional commitments increased from up to $300.0 million to up to $500.0 million. On January 22, 2017, Targa entered into definitive agreements to purchase 100% of the membership interests of Outrigger Delaware Operating, LLC, Outrigger Southern Delaware Operating, LLC (together “Outrigger Delaware”) and Outrigger Midland Operating, LLC (“Outrigger Midland” and together with “Outrigger Delaware”, “Outrigger Permian”) (the “Outrigger Permian Acquisition”). Targa will pay $475 million in cash at closing and $90 million within 90 days of closing. Subject to certain performance-linked measures and other conditions, additional cash of up to $935 million may be received by the sellers of Outrigger Permian in potential earn-out payments that may occur in 2018 and 2019. The potential earn-out payments will be based upon a multiple of realized gross margin from existing contracts. Targa currently expects to close the transaction during the first quarter of 2017, subject to customary regulatory approvals and closing conditions. Outrigger Delaware’s gas gathering and processing and crude gathering systems are located in Loving, Winkler and Ward counties. The operations are backed by producer dedications of more than 145,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 14 years. Outrigger Delaware’s assets include 70 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the Outrigger Delaware system. Outrigger Midland’s gas gathering and processing and crude gathering systems are located in Howard, Martin and Borden counties. The operations are backed by producer dedications of more than 105,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 12.5 years. Outrigger Midland currently has 10 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the Outrigger Midland system. Targa anticipates connecting Outrigger Delaware to its existing Sand Hills system and Outrigger Midland to its existing WestTX system during 2017, creating operational and capital synergies. On January 26, 2017, TRC completed a public offering of 9,200,000 shares of common stock (including the underwriters’ overallotment option) at a price of $57.65, providing net proceeds of $524.1 million.  Targa intends to use the net proceeds from this public offering to fund a portion of the $565 million initial purchase price of the Outrigger Permian Acquisition. Targa expects that the remaining portion of the purchase price and related fees and expenses will be funded with borrowings under the Partnership’s senior secured revolving credit facility or, subject to market conditions, proceeds from the issuance of private or public securities. Prior to funding the Outrigger Permian Acquisition, or if the acquisition is not completed, Targa may use the net proceeds from the equity offering for general corporate purposes, which may include, among other things, repayment of our indebtedness (including the Partnership’s indebtedness), acquisitions, capital expenditures, additions to working capital and redeeming or repurchasing some of our outstanding notes. Given the continued producer activity around its systems, Targa estimates that 2017 Field Gathering and Processing (“G&P”) natural gas inlet volumes will average at least 10% higher than 2016 Field G&P average natural gas inlet volumes. In the Permian Basin, Targa anticipates average G&P natural gas inlet volumes will increase by approximately 20% in 2017 compared to 2016.  The Permian guidance includes anticipated volumes from the acquisition of assets in the Delaware and Midland Basins announced on January 23, 2017, and subject to customary regulatory approvals and other closing conditions, Targa expects the acquisition will close during the first quarter. In SouthTX and the Badlands, Targa estimates 2017 average natural gas inlet volumes will be higher than average 2016 volumes, and Targa also expects higher average crude volumes in the Badlands year over year. These volumes increases will be partially offset by lower volumes in WestOK, SouthOK and North Texas. In the Downstream business, related to its LPG export business at Galena Park, Targa has approximately two-thirds of its current estimated export capacity of 7 million barrels per month contracted each year at attractive rates through 2022. Some years are slightly higher and some years are slightly lower than two-thirds, but two-thirds is representative of the significant percentage of current LPG export capacity contracted in each year. In support of the growth Targa is seeing in its G&P business and the additional growth opportunities upstream activity is creating in its Downstream business, Targa expects that 2017 net growth capital expenditures will be at least $700 million, based on currently announced projects and other identified spending. There are a number of other attractive G&P and Downstream projects under development, but not yet announced, that may require additional growth capex spending in 2017. Net maintenance capital expenditures for 2017 are estimated to be approximately $110 million. For full year 2017, Targa expects dividend coverage to exceed 1.0 times assuming a $3.64 per common share 2017 dividend. Inclusive of the January 23, 2017 acquisition in the Permian Basin, Targa estimates that it will not pay cash taxes for the next 5 years. Targa will host a conference call for investors and analysts at 10:00 a.m. Eastern time (9:00 a.m. Central time) on February 15, 2017 to discuss fourth quarter and full year 2016 results. The conference call can be accessed via webcast through the Events and Presentations section of Targa’s website at www.targaresources.com, by going directly to http://ir.targaresources.com/trc/events.cfm or by dialing 877-881-2598.  The conference ID number for the dial-in is 62528053. Please dial in ten minutes prior to the scheduled start time. A replay will be available approximately two hours following the completion of the webcast through the Investors section of the Company’s website. An updated investor presentation will also be available in the Events and Presentations section of the Company’s website following the completion of the conference call. (1) Gross margin, operating margin, adjusted EBITDA, and distributable cash flow are non-GAAP financial measures and are discussed under “Targa Resources Corp. – Non-GAAP Financial Measures.” (2) Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant, other than in Badlands, where it represents total wellhead gathered volume. (3) Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes. (4) These volume statistics are presented with the numerator as the total volume sold during the period and the denominator as the number of calendar days during the period. (5) Export volumes represent the quantity of NGL products delivered to third-party customers at our Galena Park Marine Terminal that are destined for international markets. (6) Includes the impact of intersegment eliminations. NM      Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful. The increase in commodity sales was primarily due to higher NGL and natural gas prices ($447.2 million), partially offset by lower NGL volumes ($32.7 million) and the impact of hedge settlements ($17.5 million). Fee-based and other revenues decreased primarily due to lower fractionation and export fees. The increase in product purchases reflects the same factors as commodity sales, which were the impact of the higher commodity prices, partially offset by lower NGL volumes. Operating margin was flat while gross margin increased slightly in 2016, which reflects increased Gathering and Processing segment margins, offset by decreased Logistics and Marketing segment margin results. Operating expenses increased compared to 2015 due to higher compensation, benefits and utilities expenses. See “—Review of Segment Performance” for additional information regarding changes in operating margin and gross margin on a segment basis. The decrease in depreciation and amortization expenses is primarily due to the $32.6 million charge in 2015 to reflect an impairment of certain gas processing facilities and associated gathering systems due to market conditions and processing spreads in Louisiana. In 2016, there were no impairments of property, plant and equipment or intangibles assets. General and administrative expenses increased primarily due to higher compensation and benefits, partially offset by lower professional services. The Company recognized an impairment of goodwill of $183.0 million during 2016 as compared with the $290.0 million provisional impairment of goodwill recorded during the fourth quarter of 2015, which was finalized in the first quarter of 2016 with an additional impairment of $24.0 million. These impairment charges relate to goodwill acquired in 2015 in connection with the Company’s acquisition of Atlas Energy LP (“ATLS”) and Atlas Pipeline Partners, LP (“APL”) (collectively, the “Atlas mergers”). Other operating (income) expense in 2016 increased as the Company reported net gains on sales of assets in 2015. Net interest expense increased primarily due to lower non-cash interest income related to the mandatorily redeemable preferred interest liability that is revalued quarterly at the estimated redemption value as of the reporting date. The estimated redemption value of the mandatorily redeemable preferred interests liability increased during 2016 as compared with a decrease in 2015. Other factors included lower capitalized interest due to decreased capital expenditures in 2016, partially offset by the impact of lower average outstanding borrowings during 2016. The decrease in equity earnings (loss) was due to lower operating results from Gulf Coast Fractionators LP (“GCF”). During 2016, the Company recorded a $69.6 million loss from financing activities that included the tender of certain senior notes of the Partnership, redemption of certain senior notes of the Partnership and the write-off of debt issuance costs associated with the amendment of the TRP revolving credit facility. In 2015, the Company incurred a net gain from financing activities of $3.5 million from the Partnership’s debt repurchases. The change in income tax (expense) benefit was primarily due to the impact of the TRC/TRP Merger, which eliminated the noncontrolling interest associated with the third-party TRP common unit holders for most of 2016. Income attributable to noncontrolling interests is not subject to income taxes in our financial statements.  Therefore, during most of 2016, we recorded income taxes on the majority of the pre-tax loss generated by TRP due to absence of the large noncontrolling interest in TRP. Net income (loss) attributable to noncontrolling interests was significantly lower for 2016 due to the absence of the third-party common noncontrolling interest that was acquired in the February 2016 TRC/TRP Merger described above. The impact of the TRP buy-in was most pronounced during the fourth quarter of both years because each included significant losses as a result of the Company’s annual goodwill impairment evaluations. The noncontrolling interest bore approximately 89% of the fourth quarter impairment loss in 2015 versus 0% in 2016. Preferred dividends in 2016 represent both cash dividends related to the March 2016 Series A Preferred Stock offering and non-cash deemed dividends for the accretion of the preferred discount related to a beneficial conversion feature. The increase in commodity sales was primarily due to the favorable impact of the inclusion of two additional months of TPL’s operations during 2016 ($270.1 million), partially offset by lower commodity prices ($53.7 million) and the impact of hedge settlements ($42.5 million). Additionally, fee-based and other revenues decreased primarily due to lower fractionation and export fees, partially offset by the impact of an additional two months of TPL’s fee revenue in 2016 ($40.9 million). The increase in product purchases was primarily due to the inclusion of two additional months of operations from TPL in 2016 ($137.5 million), partially offset by the impact of the lower commodity prices. The lower operating margin and gross margin in 2016 reflects decreased segment margin results for Logistics and Marketing, partially offset by increased Gathering and Processing segment margins. Operating expenses increased slightly compared to 2015 due to the inclusion of TPL’s operations for an additional two months in 2016, offset by a continued focused cost reduction effort throughout our operating areas. See “—Review of Segment Performance” for additional information regarding changes in operating margin and gross margin on a segment basis. The increase in depreciation and amortization expenses reflects an additional two months of TPL operations in 2016, growth investments from other system expansions including CBF Train 5, the Buffalo Plant, compressor stations and pipelines, and higher planned amortization of the Badlands intangible assets. Partially offsetting these factors was an additional $32.6 million charge to depreciation in 2015 to reflect an impairment of certain gas processing facilities and associated gathering systems in the Gathering and Processing segment due to market conditions and processing spreads in Louisiana. General and administrative expenses, which include TPL operations for an additional two months in 2016, increased primarily due to higher compensation and benefits, partially offset by lower property insurance premiums. The Company recognized impairments of goodwill totaling $207.0 million during 2016, as compared with the $290.0 million provisional impairment of goodwill recorded during the fourth quarter of 2015. Goodwill impairment recorded in 2016 includes $24.0 million recorded in the first quarter to finalize the 2015 provisional charge, as well as an additional $183.0 million associated with the Company’s annual impairment evaluation in the fourth quarter of 2016. These impairment charges relate to goodwill acquired in the 2015 Atlas mergers. Other operating (income) expense in 2016 includes the loss on decommissioning two storage wells at the Company’s Hattiesburg facility and an acid gas injection well at the Company’s Versado facility, whereas in 2015 the Company reported a net gain on sales of assets. Net interest expense increased primarily due to lower non-cash interest income related to the mandatorily redeemable preferred interests liability that is revalued quarterly at the estimated redemption value as of the reporting date. The estimated redemption value of the mandatorily redeemable preferred interests liability decreased in 2016 by a lesser amount than in 2015. Other factors included lower capitalized interest due to decreased capital expenditures in 2016, partially offset by the impact of lower average outstanding borrowings during 2016. The decrease in equity earnings (loss) was due to lower operating results from GCF and the inclusion of an additional two months of equity losses from the T2 Joint Ventures in 2016. During 2016, the Company recorded a $48.2 million loss from financing activities that included the tender of $1,138.3 million of certain senior notes of the Partnership, the repurchase of $559.2 million of certain senior notes of the Partnership in open market purchases, and the redemption of $146.2 million of certain senior notes of the Partnership. In 2015, the Company incurred a net loss from financing activities of $10.1 million from the partial repayments of the TRC senior secured term loan and the repurchase of certain senior notes of the Partnership. Other income (expense) in 2015 was primarily attributable to non-recurring transaction costs related to the Atlas mergers. The change in income tax (expense) benefit was primarily due to the decrease in income (loss) before income taxes and the impact of the TRC/TRP Merger, which eliminated the noncontrolling interest associated with the third-party TRP common unit holders for most of 2016. Income attributable to noncontrolling interests is not subject to income taxes in our financial statements.  Therefore, during most of 2016, we recorded income taxes on the majority of the pre-tax loss generated by TRP due to absence of the large noncontrolling interest in TRP. Despite similar amounts of net losses in 2016 and 2015,  net income (loss) attributable to noncontrolling interests was significantly lower for 2016 due to the February 2016 TRC/TRP Merger, which eliminated the noncontrolling interest associated with the third-party TRP common unit holders for most of 2016.  The impact of the TRP non-controlling common interest buy-in was most pronounced during the fourth quarter of both years which included significant losses as a result of our annual goodwill impairment evaluations. The noncontrolling interest bore approximately 89% of the fourth quarter impairment loss in 2015 and 0% in 2016. This reduction was partially offset by the impact of a full year of distributions in 2016 for the TRP's Preferred Units issued in October 2015. Preferred dividends in 2016 represent both cash dividends on Series A Preferred Stock and non-cash deemed dividends for the accretion of the preferred discount related to a beneficial conversion feature. The Series A Preferred Stock was issued on March 16, 2016. The following discussion of segment performance includes inter-segment activities. The Company views segment operating margin as an important performance measure of the core profitability of its operations. This measure is a key component of internal financial reporting and is reviewed for consistency and trend analysis. For a discussion of operating margin, see “Targa Resources Corp. - Non-GAAP Financial Measures - Operating Margin.” Segment operating financial results and operating statistics include the effects of intersegment transactions. These intersegment transactions have been eliminated from the consolidated presentation. For all operating statistics presented, the numerator is the total volume or sales during the applicable reporting period and the denominator is the number of calendar days during the applicable reporting period. The Company operates in two primary segments (previously referred to as divisions): (i) Gathering and Processing, previously disaggregated into two reportable segments—(a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing (also referred to as the Downstream Business), previously disaggregated into two reportable segments—(a) Logistics Assets and (b) Marketing and Distribution. Concurrent with the TRC/TRP Merger, management reevaluated the Company’s reportable segments and determined that its divisions are the appropriate level of disclosure for the Company’s reportable segments. The increase in activity within Field Gathering and Processing due to the Atlas mergers coupled with the decline in activity in the Gulf Coast region makes the disaggregation of Field Gathering and Processing and Coastal Gathering and Processing no longer warranted. Management also determined that further disaggregation of the Logistics and Marketing division is no longer appropriate due to the integrated nature of the operations within TRC’s Downstream Business and its leadership by a consolidated executive management team. The Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma and South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico. The following table provides summary data regarding results of operations of this segment for the periods indicated: (1) Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period, including the volumes related to plants acquired in the APL merger. (2) Plant natural gas inlet represents the Company’s undivided interest in the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant. (3) Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes. (4) Includes wellhead gathered volumes moved from Sand Hills via pipeline to SAOU for processing. (5) Operations acquired as part of the APL merger effective February 27, 2015. (6) Badlands natural gas inlet represents the total wellhead gathered volume. (7) Average realized prices exclude the impact of hedging activities presented in Other. Three Months Ended December 31, 2016 Compared to Three Months Ended December 31, 2015 The increase in gross margin was primarily due to higher commodity prices offset by lower throughput volumes. Total Field inlet volumes were down slightly, with increases at SAOU, WestTX, Versado and SouthTX offsetting decreases at the other areas. The inlet volume decrease for Coastal, which generates significantly lower margins than does Field, accounted for 90% of the overall inlet volume decrease. NGL production and NGL sales increased primarily due to increased plant recoveries due to additional ethane recovery and more efficient plant operations. Natural gas sales decreased due to lower inlet volumes and increased ethane recovery. Badlands natural gas and crude oil volumes decreased primarily due to the timing of producer well completion fracturing and associated shut-in of adjacent wells and to inclement weather. Excluding the impact of a one-time expense reduction settlement recorded in the fourth quarter of 2015, operating expenses for most areas were lower due to a continued focused cost reduction effort. The increase in gross margin was primarily due to the inclusion of the TPL volumes for all of 2016 and an increase in NGL prices partially offset by lower natural gas and condensate prices and lower inlet volumes in WestOK and on certain of the Company’s other systems. The plant inlet volume increase in SAOU was more than offset by reduced producer activity and volumes at Sand Hills (which also had operational issues), Versado and North Texas. Badlands natural gas volumes increased due to system expansions while crude oil volumes were essentially flat. Coastal plant inlet volumes decreased due to current market conditions and the decline of off-system volumes partially offset by additional higher GPM volumes. Excluding the impact of including operating expenses for TPL for an additional two months in 2016 and system expansions, operating expenses for most areas were lower due to a continued focused cost reduction effort. The table below provides a reconciliation between gross operating statistics and the actual reported operating statistics for the Field portion of the Gathering and Processing segment: (1) Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant. (2) Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes. (3) For these volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the  period. (4) Includes wellhead gathered volumes moved from Sand Hills to SAOU for processing. (5) Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in the Company’s reported financials. (6) Includes the Buffalo Plant that commenced commercial operations in April 2016. (7) Versado is a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials. Targa held a 63% interest in Versado until October 31, 2016, when it acquired the remaining 37% interest. (8) SouthTX includes the Silver Oak II plant, of which TPL has owned a 90% interest since January 2016, and prior to which TPL owned a 100% interest. Silver Oak II is owned by a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials. (9) SouthOK includes the Centrahoma joint venture, of which TPL owns 60%, and other plants which are owned 100% by TPL. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials. (10) Badlands natural gas inlet represents the total wellhead gathered volume. (1) Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant. (2) Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes. (3) For these volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the  period. (4) Includes wellhead gathered volumes moved from Sand Hills to SAOU for processing. (5) Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in the Company’s reported financials. (6) Includes the Buffalo Plant that commenced commercial operations in April 2016. (7) Versado is a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials. Targa held a 63% interest in Versado until October 31, 2016, when it acquired the remaining 37% interest. (8)  SouthTX includes the Silver Oak II plant, of which TPL has owned a 90% interest since January 2016, and prior to which TPL owned a 100% interest. Silver Oak II is owned by a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials. (9) SouthOK includes the Centrahoma joint venture, of which TPL owns 60%, and other plants which are owned 100% by TPL. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials. (10) Badlands natural gas inlet represents the total wellhead gathered volume. The Logistics and Marketing segment includes all the activities necessary to convert mixed NGLs into NGL products and provides certain value added services such as storing, terminaling, distributing and marketing of NGLs, the storage and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of Targa’s other businesses including services to LPG exporters. It also includes certain natural gas supply and marketing activities in support of the Company’s other operations, as well as transporting natural gas and NGLs. Logistics and Marketing operations are generally connected to and supplied in part by the Company’s Gathering and Processing segments and are predominantly located in Mont Belvieu and Galena Park, Texas, Lake Charles, Louisiana and Tacoma, Washington. The following table provides summary data regarding results of operations of this segment for the periods indicated: (1) Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period. (2) Fractionation and treating contracts include pricing terms composed of base fees and fuel and power components which vary with the cost of energy.  As such, the Logistics and Marketing segment results include effects of variable energy costs that impact both gross margin and operating expenses. (3) Fractionation volumes reflect those volumes delivered and settled under fractionation contracts. (4) Export volumes represent the quantity of NGL products delivered to third-party customers at Targa’s Galena Park Marine Terminal that are destined for international markets. Three Months Ended December 31, 2016 Compared to Three Months Ended December 31, 2015 Logistics and Marketing gross margin decreased due to lower LPG export margin, partially offset by higher marketing gains, higher fractionation margin, and higher treating volumes. LPG export margin decreased due to lower fees, partially offset by higher volumes.  Fractionation margin increased primarily due to higher fees and favorable system product gains, partially offset by lower supply volumes. Fractionation margin was partially impacted by the variable effects of fuel and power which are largely reflected in operating expenses (see footnote (2) above). Operating expenses increased primarily due to higher compensation and benefits, higher fuel and power and the startup of CBF Train 5, partially offset by lower ad valorem taxes as a result of an adjustment from forecasted to actual. Logistics and Marketing gross margin decreased primarily due to lower LPG export margin and the realization in 2015 of contract renegotiation fees related to the Company’s crude oil and condensate splitter project. Gross margin also decreased due to lower fractionation margin and lower terminaling and storage throughput, partially offset by higher NGL marketing gains. LPG export margin decreased due to lower fees. Fractionation margin decreased primarily due to lower supply volume and lower system product gains, partially offset by higher fees. Fractionation margin was partially impacted by the variable effects of fuel and power which are largely reflected in operating expenses (see footnote (2) above). Operating expenses were relatively flat. Higher compensation and benefits and higher ad valorem taxes associated with the start-up of CBF Train 5 were largely offset by lower fuel and power, and lower maintenance expense resulting from continued focused cost reductions. Other contains the results (including any hedge ineffectiveness) of commodity derivative activities included in operating margin and mark-to-market gain/losses related to derivative contracts that were not designated as cash flow hedges. The primary purpose of Targa’s commodity risk management activities is to mitigate a portion of the impact of commodity prices on its operating cash flow. The Company has hedged the commodity price associated with a portion of its expected (i) natural gas equity volumes and (ii) NGL and condensate equity volumes in its Gathering and Processing Operations that result from percent of proceeds or liquid processing arrangements by entering into derivative instruments. Because the Company is essentially forward-selling a portion of its plant equity volumes, these hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices. The following table provides a breakdown of the change in Other operating margin: (1) The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction. (2) Mark-to-market income (loss) associated with derivative contracts that are not designated as hedges for accounting purposes. (3) Ineffectiveness primarily relates to certain crude hedging contracts and certain acquired hedges of APL that do not qualify for hedge accounting. As part of the Atlas mergers, outstanding APL derivative contracts with a fair value of $102.1 million as of the acquisition date were novated to the Company and included in the acquisition date fair value of assets acquired. Derivative settlements of $26.6 million and $67.9 million related to these novated contracts were received during the years ended December 31, 2016 and December 31, 2015, respectively, and were reflected as a reduction of the acquisition date fair value of the APL derivative assets acquired with no effect on results of operations. Targa Resources Corp. is a leading provider of midstream services and is one of the largest independent midstream energy companies in North America. Targa owns, operates, acquires, and develops a diversified portfolio of complementary midstream energy assets. The Company is primarily engaged in the business of: gathering, compressing, treating, processing, and selling natural gas; storing, fractionating, treating, transporting, and selling NGLs and NGL products, including services to LPG exporters; gathering, storing, and terminaling crude oil; and storing, terminaling, and selling refined petroleum products. The principal executive offices of Targa are located at 1000 Louisiana, Suite 4300, Houston, TX 77002 and their telephone number is 713-584-1000.  For more information please go to www.targaresources.com. This press release includes the Company’s non-GAAP financial measures Adjusted EBITDA, distributable cash flow, gross margin and operating margin. The following tables provide reconciliations of these non-GAAP financial measures to their most directly comparable GAAP measures. The Company’s non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income, operating income, net cash flows provided by operating activities or any other GAAP measure of liquidity or financial performance. The Company defines Adjusted EBITDA as net income (loss) available to TRC before: interest; income taxes; depreciation and amortization; impairment of goodwill; gains or losses on debt repurchases, redemptions, amendments, exchanges and early debt extinguishments and asset disposals; risk management activities related to derivative instruments including the cash impact of hedges acquired in the APL merger; non-cash compensation on equity grants; transaction costs related to business acquisitions; the Splitter Agreement adjustment; net income attributable to TRP preferred limited partners; earnings/losses from unconsolidated affiliates net of distributions, distributions from preferred interests, change in contingent consideration and the noncontrolling interest portion of depreciation and amortization expenses. Adjusted EBITDA is used as a supplemental financial measure by the Company and by external users of the Company’s financial statements such as investors, commercial banks and others. The economic substance behind the Company’s use of Adjusted EBITDA is to measure the ability of the Company’s assets to generate cash sufficient to pay interest costs, support our indebtedness and pay dividends to the Company’s investors. Adjusted EBITDA is a non-GAAP financial measure. The GAAP measure most directly comparable to Adjusted EBITDA is net income (loss) attributable to TRC. Adjusted EBITDA should not be considered as an alternative to GAAP net income. Adjusted EBITDA has important limitations as an analytical tool. Investors should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies in the Company’s industry, the Company’s definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility. Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into our decision-making processes. The Company defines distributable cash flow as Adjusted EBITDA less distributions to TRP preferred limited partners, the Splitter Agreement adjustments, cash interest expense on debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs). This measure includes the impact of noncontrolling interests on the prior adjustment items. Distributable cash flow is a significant performance metric used by the Company and by external users of the Company’s financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by the Company (prior to the establishment of any retained cash reserves by our board of directors) to the cash dividends the Company expects to pay its shareholders. Using this metric, management and external users of the Company’s financial statements can quickly compute the coverage ratio of estimated cash flows to cash dividends. Distributable cash flow is also an important financial measure for the Company’s shareholders since it serves as an indicator of the Company’s success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not the Company is generating cash flow at a level that can sustain or support an increase in the Company’s quarterly dividend rates. Distributable cash flow is a non-GAAP financial measure. The GAAP measure most directly comparable to distributable cash flow is net income (loss) attributable to TRC. Distributable cash flow should not be considered as an alternative to GAAP net income (loss) available to common and preferred shareholders. It has important limitations as an analytical tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of the Company’s results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently by different companies in the Company’s industry, the Company’s definition of distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility. Management compensates for the limitations of distributable cash flow as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these insights into the Company’s decision-making processes. The following table presents a reconciliation of net income of the Company to Adjusted EBITDA and Distributable Cash Flow for the periods indicated: (1) The definition of Adjusted EBITDA was revised in 2015 to exclude earnings from unconsolidated investments net of distribution and transactions costs related to business acquisitions. (2) In Adjusted EBITDA, the amount reflects the annual cash payment received for the Splitter Agreement recognized over the four quarters following receipt. In distributable cash flow, the amounts reflect the annual cash payment in the period received less the amount recognized in Adjusted EBITDA. (3) Noncontrolling interest portion of depreciation and amortization expenses. (4) Excludes amortization of interest expense. (5) Includes an adjustment, reflecting the benefit from net operating loss carryback to 2015 and 2014, which is recognized over a period of six quarters beginning in Q3 2016. The Company defines gross margin as revenues less product purchases. It is impacted by volumes and commodity prices as well as by the Company’s contract mix and commodity hedging program. Gathering and Processing segment gross margin consists primarily of revenues from the sale of natural gas, condensate, crude oil and NGLs and fee revenues related to natural gas and crude oil gathering and services, less producer payments and other natural gas and crude oil purchases. The gross margin impacts of cash flow hedge settlements are reported in Other. The Company defines operating margin as gross margin less operating expenses. Operating margin is an important performance measure of the core profitability of its operations. Management reviews business segment gross margin and operating margin monthly as a core internal management process. The Company believes that investors benefit from having access to the same financial measures that management uses in evaluating its operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures by management and by external users of the Company’s financial statements, including investors and commercial banks, to assess: Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is net income. Gross margin and operating margin are not alternatives to GAAP net income and have important limitations as analytical tools. Investors should not consider gross margin and operating margin in isolation or as a substitute for analysis of the Company’s results as reported under GAAP. Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies in the Company’s industry, the Company’s definitions of gross margin and operating margin may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes. The following table presents a reconciliation of net income to operating margin and gross margin for the periods indicated: Certain statements in this release are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future, are forward-looking statements. These forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside the Company’s control, which could cause results to differ materially from those expected by management of the Company. Such risks and uncertainties include, but are not limited to, weather, political, economic and market conditions, including a decline in the price and market demand for natural gas, natural gas liquids and crude oil, the timing and success of business development efforts; and other uncertainties. These and other applicable uncertainties, factors and risks are described more fully in the Company’s filings with the Securities and Exchange Commission, including its Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. The Company does not undertake an obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. Contact investor relations by phone at (713) 584-1133.


ATLANTA--(BUSINESS WIRE)--TRC Staffing Services, Inc. and TRC Professional Solutions announced today that both companies have received Inavero’s Best of Staffing® Client and Talent Awards for providing superior service to their clients and job seekers. Presented in partnership with CareerBuilder, Inavero’s Best of Staffing winners have proven to be industry leaders in service quality based completely on the ratings given to them by their clients and the permanent and temporary employees they’ve helped find jobs. On average, clients of winning agencies are 2.5 times more likely to be completely satisfied and talent of winning agencies are 3.6 times more likely to be completely satisfied with the services provided compared to those working with non-winning agencies. Award winners make up less than two percent of all staffing agencies in the U.S. and Canada who earned the Best of Staffing Award for service excellence. Focused on helping to connect people with the right job openings, TRC Staffing Services, Inc. received satisfaction scores of 9 or 10 out of 10 from 71 percent of their clients and 80 percent of their talent, while TRC Professional Solutions received satisfaction scores of 9 out of 10 from 72 percent of their clients and 73 percent of their talent. Both sets of scores are significantly higher than the industry’s average. “The ‘Best of Staffing’ recognition from Inavero is one we take great pride in here at TRC,” said Brian Robinson, President and CRO, TRC Staffing Solutions, Inc. “The award means that we put our clients and talent first every time, and that we continue to deliver great services on both fronts. That is what we strive for and we intend to continue in our efforts to deliver the best service in the industry.” "Staffing firms are giving top companies a competitive advantage as they search for talent in North America," said Inavero's CEO Eric Gregg. "The 2017 Best of Staffing winners have achieved exceptionally high levels of satisfaction and I'm proud to feature them on BestofStaffing.com." TRC Staffing Services, Inc. is a full-service staffing solutions provider with over 36 years of industry experience. Established in 1980, TRC is one of the largest privately-held staffing firms in the country. Like his father, President and CEO Brian Robinson remains focused on the idea that the marketplace continues to need a business built on principles and values, committed to providing the highest level of service in the industry. TRC has 40 locations in 13 states, providing traditional staffing services, professional and technical staffing, and management services to some of the country's leading companies. For more information, visit www.trcstaffing.com. Inavero administers more staffing agency client and talent satisfaction surveys than any other firm in the world. Inavero’s team reports on over 1.2 million satisfaction surveys from staffing agency clients and talent each year and the company serves as the American Staffing Association’s exclusive service quality partner. About Inavero’s Best of Staffing Inavero’s Best of Staffing® Award is the only award in the U.S. and Canada that recognizes staffing agencies that have proven superior service quality based completely on the ratings given to them by their clients and job candidates. Award winners are showcased by city and area of expertise on BestofStaffing.com – an online resource for hiring professionals and job seekers to find the best staffing agencies to call when they are in need.


News Article | February 15, 2017
Site: www.prweb.com

The MIAMI Association of REALTORS® (MIAMI) has elected Lynne Rifkin, Broker Associate, ABR, MRP, PMN, SRES as the 2017 President of the Jupiter-Tequesta-Hobe Sound Association of Realtors (JTHS) Council. She and the entire 2017 JTHS Board of Governors were installed Dec. 2 at Frenchman’s Creek Beach & Country Club in Palm Beach Gardens. JTHS merged with MIAMI in September 2015. MIAMI assumed most JTHS administrative functions, allowing JTHS leadership and staff to focus on assisting and building the success of its members. JTHS headquarters are in Jupiter, Fla. The JTHS Board of Governors has continued leading and directing the services, issues and needs of their more than 2,500 members in Palm Beach and Martin counties. “The JTHS Board of Governors is looking forward to another year of interpreting our local markets, participating in community service and promoting South Florida real estate worldwide,” Rifkin said. “We are stronger when we stand together and promote cooperation amongst real estate professionals for the clients they serve.” JTHS Leaders impact key policy decisions, analyze industry information and are actively involved in real estate related issues, events and programming in Palm Beach and Martin counties. Originally from the Bucks County/Philadelphia area, Rifkin began selling real estate in New Jersey, along the New Jersey Eastern Coastal shoreline, from Toms River through Long Beach Island to Atlantic City. Previously, she worked in mechanical contracting sales and refrigerant management. Rifkin is currently a broker associate at Keller Williams of the Palm Beaches and partners as a team with her husband, Ron Jangaard, CIPS, GRI, TRC, e-PRO, GPS, MRP, providing seniors, military, and global relocation specialized services and luxury home sales and leases. Rifkin is also the owner/founder of HSN Homes Solutions Network LLC, which offers supportive home watch and tenant screening for clients seeking assistance with the selection of tenants for their income producing rental properties. Rifkin moved her business to Keller Williams Realty in November 2008 and joined their management team in 2012, as broker on Site. In 2013, her office was recognized as the No. 1 office for both productivity and profitability awards in the entire South Florida Region of more than 25 locations. She continues expanding her team with results-oriented service with attention to details in the Palm Beaches, Martin and St. Lucie counties. Among her many accomplishments, Rifkin received the 2010 Culture Award from Keller Williams Jupiter, as the ALC Culture Committee Chairman for Keller Williams Cares, which is a 501(c)(3) public charity created to support Keller Williams associates and their families with hardship as a result of a sudden emergency or long term illness. She is a three-time Centurion award winner, five-time Keller Williams Medallion award winner and a seven-year Keller Williams Agent Leadership Council member and former Assistant Team Leader and Fast Start Instructor. In addition to her volunteer service with JTHS and MIAMI, and serving as past president for the National Association of Women in Construction and the Association of Plant Engineers of Palm Beach County, Rifkin has served on numerous other state and national boards. In 2015, 2016, and 2017 she has been appointed to serve as a National Association of REALTORS® (NAR) director and a Florida Realtors state director. In 2011, she served as the JTHS chapter president for the Women’s Council of Realtors and then served as WCR’s Florida state district vice president in 2014. Rifkin is also an active member of her community and a former board member of the Jupiter Tequesta Junior Women’s Club and General Federation of Women national organization. Most recently she serves as a volunteer helping veterans in Jupiter and Tequesta through a group that works anonymously providing support to veterans and their families with food, respite and lodging. Most are wounded warriors from the U.S. armed services. Announcing the 2017 JTHS Board of Governors Joining Rifkin are: JTHS President-Elect Barb Fox, RSPS, ePRO of One World Realty; 2016 JTHS President Sue Gaieski, e-PRO, SFR of Water Pointe Realty Group; Governor David Abernathy of Waterfront Properties & Club Communities; Governor Jill Barnwell of Keyes Company; Governor Joshua Escoto, LEED AP of Escoto Realty Advisors; Governor Martha Gillespie-Beeman, ABR, CNE, GRI of Sheehan Realty Corporation; Governor Matthew Krause of Forbes Realty of South Florida; Governor Lou Ludwig, e-PRO, GRI of Ludwig & Associates; Governor Bill Mate of Paradise Real Estate International; Governor Charlene Oakowsky, ABR, BPRO, CAM, CDPE, ePRO, GRI, PMN, TRC of Oakowsky Properties Inc.; Governor Kim Price, CIPS of Paradise Real Estate International; Governor Anton Seiss, SBR, CCIM, CDPE, CRS, CHLMS, CIPS of Seiss Real Estate; Governor Courtney Smitheman of Crane Reed Properties, LLC; Governor Karen Tyree of Illustrated Properties/Hobe Sound; Governor Shereen Vahabzadeh of Premier Properties of South Florida; Governor Brad Westover of Keller Williams Realty Jupiter; Business Partner Governor Danny Poulos of Elite Lending Team at Inlet Mortgage; Business Partner Governor Pamela Van Woerkom of Sage Title & Escrow. Joanne Werstlein serves as JTHS Vice President. Danielle Y. Clermont is the MIAMI Senior VP of Broward, Palm Beach & Martin Counties. Teresa King Kinney serves as the Chief Executive Officer of MIAMI. About the Jupiter-Tequesta-Hobe Sound (JTHS) Council The Jupiter-Tequesta-Hobe Sound Council (JTHS) of MIAMI Association of REALTORS® (MIAMI) seeks to serve, unify and lead residential members in Palm Beach and Martin counties. With more than 2,500 members in Palm Beach and Martin Counties, the JTHS Council provides members with a legislative voice, education opportunities, a code of ethics, networking opportunities and more. JTHS merged with the MIAMI Association of REALTORS® in September 2015. The JTHS official website is http://www.jthsrealtors.com. About the MIAMI Association of REALTORS® The MIAMI Association of REALTORS® was chartered by the National Association of Realtors in 1920 and is celebrating 97 years of service to Realtors, the buying and selling public, and the communities in South Florida. Comprised of six organizations, the Residential Association, the Realtors Commercial Alliance, the Broward Council, the Jupiter Tequesta Hobe Sound (JTHS) Council, the Young Professionals Network (YPN) Council and the award-winning International Council, it represents nearly 45,000 real estate professionals in all aspects of real estate sales, marketing, and brokerage. It is the largest local Realtor association in the U.S., and has official partnerships with 160 international organizations worldwide. MIAMI’s official website is http://www.miamire.com


News Article | March 1, 2017
Site: www.nature.com

No statistical methods were used to predetermine sample size. The experiments were not randomized and the investigators were not blinded to allocation during experiments and outcome assessment. E14 mouse ES cells were cultured in high-glucose DMEM (Invitrogen) supplemented with 15% FBS (Millipore), 0.1 mM non-essential amino acids (Invitrogen), 1 mM sodium pyruvate (Invitrogen), 0.1 mM 2-mercaptoethanol, 1500 U ml−1 LIF (Millipore), 25 U ml−1 penicillin, and 25 μg ml−1 streptomycin. The cells were mycoplasma free. Generation of Dnmt3b−/− ES cells was performed using TALEN technology. Cells were transfected with the two TALEN constructs targeting exon 17 of murine Dnmt3b (corresponding to the start of the catalytic domain) and after 16 h were seeded as a single cell. After ten days, clones were screened by western blot analysis. Positive clones were analysed by genomic sequencing. For half-life measurements and Pol II elongation inhibition, wild-type and Dnmt3b−/− ES cells were treated with DRB at the concentration of 75 μM for the indicated times. For total cell extracts, cells were resuspended in F-buffer (10 mM Tris-HCl pH 7.0, 50 mM NaCl, 30 mM Na-pyrophosphate, 50 mM NaF, 1% Triton X-100, anti-proteases) and sonicated for three pulses. Extracts were quantified using BCA assay (Pierce) and were run on SDS-polyacrylamide gels at different percentages, transferred to nitrocellulose membranes and incubated with specific primary antibodies overnight. Nuclear protein extractions were performed as described in ref. 41. In brief, cells were harvested in PBS 1× and resuspended in isotonic buffer (20 mM HEPES pH 7.5, 100 mM NaCl, 250 mM sucrose, 5 mM MgCl , 5 μM ZnCl ). Successively, cells were resuspended in isotonic buffer supplemented with 1% NP-40 to isolate nuclei. The isolated nuclei were resuspended in digestion buffer (50 mM Tris-HCl pH 8.0, 100 mM NaCl, 250 mM sucrose, 0.5 mM MgCl , 5 mM CaCl , 5 μM ZnCl ) and treated with Microccocal Nuclease (NEB) at 30 °C for 10 min. Nuclear proteins from about 1 × 107 cells were incubated with 3 μg of specific antibody overnight at 4 °C. Immunocomplexes were incubated with protein-G-conjugated magnetic beads (DYNAL, Invitrogen) for 2 h at 4 °C. Samples were washed four times with digestion buffer supplemented with 0.1% NP-40 at RT. Proteins were eluted by incubating with 0.4 M NaCl TE buffer for 30 min and were analysed by western blotting. Custom shRNAs against SetD2, Dis3 and Rrp6 were constructed using the TRC hairpin design tool (http://www.broadinstitute.org/rnai/public/seq/search), and designed to target the 3′ UTR. shRNAs with more than 14 consecutive matches to non-target transcripts were avoided. Hairpins were cloned into pLKO.1 vector (Addgene: 10878) and each construct was verified by sequencing. Dnmt3b construct was obtained by PCR amplification and cloned into pEF6/V5-His vector (Invitrogen). The Dnmt3b mutant constructs (V725G, S277P and VW-RR) were generated by introducing a site-specific mutation in the DNA sequence corresponding to Val725 to mutate it into a glycine, or Ser277 to mutate it into a proline, or Val236Trp237 to mutate it to Arg–Arg, using QuickChange XL Site-Directed Mutagenesis Kit (Agilent Technologies). Transfections of mouse ES cells were performed using Lipofectamine 2000 Transfection Reagent in according to manufacturer’s protocol using equal amounts of each plasmid in multiple transfections. For SetD2 knockdown, cells were transfected with 5 μg of the specific shRNA construct, and maintained in medium with puromycin selection (1 μg ml−1) for 48 h. To investigate the distribution of the endogenous Dnmt3b we tested different antibodies and found one that was able to immunoprecipitate the endogenous Dnmt3b cross-linked to chromatin, which showed no background signal in Dnmt3b−/− (Extended Data Fig. 1g–i). The ChIP-seq data were validated by ChIP–qPCR, using several biological replicates, on target genomic regions and by crosslinked co-immunoprecipitation experiments between Dnmt3b and H3K36me3 in wild-type or Dnmt3b−/− ES cells (Extended Data Fig. 1o, p). For Dnmt3b ChIP-seq, approximately 2 × 107 cells were cross-linked by addition of formaldehyde to 1% for 10 min at RT, quenched with 0.125 M glycine for 5 min at RT, and then washed twice with cold PBS. The cells were resuspended in lysis buffer 1 (50 mM HEPES-KOH pH 7.5, 140 mM NaCl, 1 mM EDTA, 10% glycerol, 0.5% NP-40, 0.25% Triton X-100 and protease inhibitor) to disrupt the cell membrane and in lysis buffer 2 (10 mM Tris-HCl pH 8.0, 200 mM NaCl, 1 mM EDTA, 0.5 mM EGTA and protease inhibitor) to isolate nuclei. The isolated nuclei were then resuspended in SDS ChIP Buffer (20 mM Tris-HCl pH 8.0, 10 mM EDTA, 1% SDS and protease inhibitors). Extracts were sonicated using the BioruptorH Twin (Diagenode) for two runs of ten cycles (30 s on, 30 s off) at high-power setting. Cell lysate was centrifuged at 12,000g for 10 min at 4 °C. The supernatant was diluted with ChIP dilution buffer (20 mM Tris-HCl pH 8.0, 150 mM NaCl, 2 mM EDTA, 1% Triton) before the immunoprecipitation step. Magnetic beads (Dynabeads rat anti-mouse IgM for anti-Pol II-phospho-S5, Dynabeads Protein G for all the other ChIPs, Life Technologies) were saturated with PBS/1% BSA and the samples were incubated with 2 μg of antibody overnight at 4 °C on a rotator. Next day samples were incubated with saturated beads for two hours at 4 °C on a rotator. Successively immunoprecipitated complexes were washed five times with RIPA buffer (50 mM HEPES-KOH pH 7.6, 500 mM LiCl, 1 mM EDTA, 1% NP-40, 0.7% Na-Deoxycholate) at 4 °C for 5 min each on a rotator. For other ChIP-seq, ChIP-seq was performed as described previously42. Elution buffer was added and incubated at 65 °C for 15 min. The de-crosslinking was performed at 65 °C overnight. De-crosslinked DNA was purified using QiaQuick PCR Purification Kit (Quiagen) according to the manufacture’s instruction. MeDIP was performed using MeDIP kit (Active Motif), according to the manufacturer’s protocol. DNA was analysed by quantitative real-time PCR by using SYBR GreenER kit (Invitrogen). All experiment values were normalized to input. The data shown represent triplicate real-time quantitative PCR measurements of the immunoprecipitated DNA. The data are expressed as a percentage of the DNA inputs. Error bars represent standard deviation determined from triplicate experiments. Oligonucleotide sequences are reported in Supplementary Table 1. Genomic DNA was extracted from cells using DNeasy Blood and Tissue kit (Qiagen). For dot-blot analysis, extracted genomic DNA was sonicated using the BioruptorH Twin (Diagenode) for two runs of ten cycles (30 s on, 30 s off) at high-power setting, in order to obtain 300-bp fragments, denatured with 0.4 M NaOH and incubated for 10 min at 95 °C before being spotted onto HybondTM-N+ (GE Healthcare). Membranes were saturated with 5% milk and incubated with the specific antibodies overnight. Approximately 10 ng of purified ChIP DNA were end-repaired, dA-tailed, and adaptor-ligated using the NEBNext ChIP-seq Library Prep Master Mix Set (NEB), following the manufacturer’s instructions. For whole-genome bisulphite-seq library preparation, 2.5 μg of ES cells genomic DNA, were spiked-in with 1 ng of Escherichia coli genomic DNA, and sheared using a Bioruptor Twin sonicator (Diagenode) for three runs of ten cycles (30 s on, 30 s off) at high-power setting. Fragmented/digested DNA was then end-repaired, dA-tailed, and ligated to methylated adapters, using the Illumina TruSeq DNA Sample Prep Kit, following manufacturer instructions. DNA was loaded on EGel Size select 2% agarose pre-cast gel (Invitrogen), and a fraction corresponding to fragments ranging from 180 bp to 350 bp was recovered. Purified DNA was then subjected to bisulphite conversion using the EpiTect Bisulphite Kit (Qiagen). Bisulphite-converted DNA was finally enriched by 15 cycles of PCR using Pfu Turbo Cx HotStart Taq (Agilent). Total RNA was extracted as previously described43 using TRIzol reagent (Invitrogen). Real-time PCR was performed using the SuperScript III Platinum One-Step Quantitative RT–PCR System (Invitrogen) following the manufacturer’s instructions. Ribo-RNA-seq library preparation was performed as described previously44. In brief, 2.5 μg of total RNA were depleted of ribosomal RNA using the RiboMinus Eukaryote System v2 kit (Invitrogen), following manufacturer instructions. Ribo-RNA was resuspended in 17 μl of EFP buffer (Illumina), heated to 94 °C for 8 min, and used as input for first strand synthesis, using the TruSeq RNA Sample Prep kit, following manufacturer instructions. Poly(A) RNA-seq library was performed by using the TruSeq RNA Sample Prep kit, following the manufacturer’s instructions. For immunoprecipitation of mRNA for CAP-Seq experiments, 30 μg of total RNA were fragmented by alkaline hydrolysis in ~200-nt fragments and incubated with 5 μg of mouse anti-CAP antibody (anti-m3G-cap, m7g-cap, Clone H20, Millipore MABE419) (or IgG) overnight at 4 °C in 0.5 ml of IP buffer (10 mM Tris-HCl pH 7.5; 150 mM NaCl; 0.1% Triton X-100) supplemented with 50 U ml−1 RNaseOUT (Invitrogen), 50 U ml−1 SuperaseIN (Invitrogen), and 50 U ml−1 RNase Inhibitor (Ambion). 25 μl of Dynabeads Protein G (Invitrogen) were saturated overnight at 4 °C in IP buffer supplemented with 150 μg of Sonicated Salmon Sperm DNA (Qiagen). Following incubation, beads were washed two times in IP buffer and incubated with the preformed RNA-antibody complexes at 4 °C. After 3 h, beads were washed four times with IP buffer. Specific elution of recovered fragments were obtained by incubation of beads with 100 μl elution buffer (5 mM Tris pH 7.5; 1 mM EDTA; 0.05% SDS; 0.3 mg ml−1 Proteinase K) for 1.5 h at 50 °C. Fragments were then purified by addition of 1 ml of TRIzol reagent (Invitrogen), and subjected to random-primed reverse transcription using the SuperScript III Reverse Trancriptase (Invitrogen) at 50 °C for 1 h. Resulting cDNAs were then used as input for the TruSeq RNA Sample Prep kit (Illumina), starting from the ‘second strand synthesis’ step, to produce the sequencing library, following the manufacturer’s instruction. To map the transcriptional start sites at single-base resolution we used an enzymatic-based approach by the use of the RNA 5′ pyrophosphohydrolase (RppH) enzyme to decap eukaryotic mRNAs21. We validated the specificity of this technique in a pilot experiment by comparing RppH-treated RNA versus untreated or T4 polynucleotide kinase (PNK)-treated RNA (Extended Data Fig. 6a–e). When required the total RNA was depleted from small nuclear RNAs (snRNAs) by using the following protocol. 5 μg of total RNA was resuspended in snRNA-depletion buffer (20 mM HEPES pH 7.5, 80 mM KCl, 1 mM DTT), 1 μl RNase inhibitor (Ambion), 2 μM oligo mix (designed against snRNAs sequences, primers sequences in Supplementary Table 1) in a final volume of 50 μl, heated to 70 °C for 5 min and immediately put on ice. After that it was added 25 μl snRNA-depletion buffer 2 × (40 mM HEPES pH 7.5, 160 mM KCl, 10 mM MgCl , 2 mM DTT), supplemented with 1 μl RNase inhibitor (Ambion) and 1 μl of RNAse H (NEB) to a final volume of 100 μl. Incubated for 30 min at 37 °C. snRNA-depleted RNA were purified by RNA Clean and Concentration kit (Zymo Research) and DNaseI digestion was performed following the manufacturer’s instructions. snRNA-depleted RNAs were further depleted from ribosomal RNA by using the RiboMinus Eukaryote System v2 kit (Invitrogen). The RNA obtained from previous depletions (or poly(A)+ RNA enriched using NEBNext Poly(A) mRNA Magnetic Isolation Module kit (NEB), following the manufacturer’s instructions) was chemically fragmented by using first strand buffer of the SuperScript II Reverse Transcriptase (Invitrogen). The fragmented RNA was dephosphorylated of natural 5′ and fragmentation-derived 3′ phosphate by using Antarctic Phosphatase (AP, NEB). Dephosphorylated RNA was then treated with RNA 5′ pyrophosphohydrolase (RppH, NEB) in 1 × Thermopol buffer (NEB) (for decapping and pyrophosphate removal from the 5′ end of RNA to leave a 5′ monophosphate RNA). For positive and negative control, the dephosphorylated RNA was treated with the T4 polynucleotide kinase (PNK, NEB) (for 5′ phosphorylation of all RNA fragments) or was performed without adding the enzyme. 5′ RNA adaptor ligation was carried out by using the TruSeq Small RNA Sample Preparation Kit (Illumina). Reverse transcription was performed with SuperScript III enzyme (Invitrogen) and Illumina 3′ Adaptor Rev-Comp Random Hexamers (RC3N6). The RNA was size selected on TBE-Urea 10% PAGE gel and PCR amplification was carried out by using the TruSeq Small RNA Sample Preparation Kit (Illumina). Ribosome profiling was performed using the ARTseq/TruSeq Ribo Profile (Illumina), with minor changes to the manufacturer protocol. In brief, around 3 × 107 cells were treated with 0.1 μg μl−1 final cycloheximide for 5 min at 37 °C. Cells were then washed twice and harvested with ice-cold PBS (supplemented with 0.1 μg μl−1 final cycloheximide). Cells were lysed in 1 ml of mammalian lysis buffer (supplemented with 0.5% final concentration of NP-40) at 4 °C for 10 min on a rotator. The lysate was then treated with 50 U of ART-seq nuclease for 45 min at 25 °C, with moderate shaking. 400 μl of the digested lysate were then layered on the top of a 2.5 ml sucrose cushion, and centrifuged at 265,000g for 5 h at 4 °C. After completely removing the supernatant, the pellet was resuspended in 100 μl nuclease-free water, and purified on RNA Clean & Concentrator-5 columns (Zymo Research). 5 μg of the recovered monosomal RNA was then subjected to two consecutive rounds of rRNA depletion using the Ribo-Zero Gold Kit (Human/Mouse/Rat, Epicentre), and then run on a 10% TBE-Urea PAGE gel for 25 min at 200 V. A gel slice corresponding to 28–30 nt was then cut, crushed, and RNA was recovered by passive diffusion at 4 °C for 16 h. The eluted RNA fragments were then end-repaired, ligated to the 3′ adaptor, and reverse-transcribed. The cDNA was run on 10% TBE-Urea PAGE gel for 30 min at 180 V, and a gel slice corresponding to fragments of approximately 70–80 nt was cut, crushed, and cDNA was recovered by passive diffusion at 37 °C for 16 h with vigorous shaking. The eluted cDNA was then subjected to circularization, and the final library was obtained by ten cycles of PCR. The final library was inspected on the Fragment Analyzer (Advanced Analytical), revealing a single sharp peak around 150 bp. Samples were sequenced on the HiScanSQ or Next500 platforms (Illumina). All of the analysed datasets were mapped to a recently published variant of the mm9 genome assembly that includes single-nucleotide variants from E14 ES cells45. Prior to mapping, sequencing reads were trimmed on the basis of low-quality scores and clipped from the adaptor sequence by using FASTX toolkit (http://hannonlab.cshl.edu/fastx_toolkit/). For RNA-seq data analysis, reads were mapped using TopHat v2.0.6 (ref. 46) and mRNA quantification was performed using Cuffdiff v2.0.2 (ref. 47). For ChIP-seq data analysis, reads were mapped Bowtie version 0.12.7 (ref. 48), reporting only unique hits with up to two mismatches (parameters: -m 1 -v 2). For bisulphite-seq data analysis, reads were mapped using BSMAP v2.74 (ref. 49). Unmapped reads from the first mapping round were trimmed by 10 nt at their 5′ end, and 15 nt at their 3′ end using fastx_trimmer tool from the FASTX toolkit, and subjected to a second round of mapping. Reads failing this second mapping round were mapped to the Escherichia coli strain K-12 substrain DH10B genome (NCBI accession: NC_010473), in order to estimate bisulphite conversion efficiency. RNA-seq correlation analyses were performed by using Pearson correlation coefficient and by plotting RPKM value calculated on RefFlat gene annotation. Intragenic transcription initiation analysis was performed on a non-redundant gene annotation built starting from the RefFlat annotation, by keeping only the longest isoform for each gene, with at least 1 RPKM of expression and at least 5 exons. RPKM on each exon was calculated by counting reads falling in the exon (normalizing on the exon length in kb and on the total mapped reads of the experiment in millions) using custom script and then the ratio was calculated as the log fold-change of second, third and last exon RPKM over the first exon RPKM for each gene. For the ratio of intermediate to first exons, averages of the RPKM value of all the other exons (from fourth to penultimate) were used. Alternative promoter analysis was performed on a non-redundant gene annotation built starting from the RefFlat annotation by keeping only the genes that had at least two isoforms transcribed from known different promoters. RPKM of the first exon of the isoforms transcribed from alternative promoters was calculated with a custom script. The log ratio between the first exons transcribed from the first over the second promoter was plotted by using the heatscatter function (on R) and correlation was quantified with Pearson’s coefficient. Alternative promoter analysis was calculated on the same reference as above. The log ratio was calculated as the RPKM value of the first exon transcribed from each class of different alternative promoters over the RPKM of the whole transcript, in order to normalize differentially expressed genes in wild-type and Dnmt3b−/− cells. For DECAP-seq only intragenic mapped reads were used for further analysis. We used a RefSeq-based genic reference containing only the annotated longest isoforms and deprived from all the genes overlapping other genes or ncRNAs on the same strand. Since DECAP-seq is a technique capable of single-base resolution and the first base of the sequenced reads corresponds to the base having the cap signal, only the first position of the mapped read was used to calculate a count per million of mapped reads (RPM). All the analyses were performed on the genes belonging to the third or fourth quartiles of expression. Venn diagram overlap is calculated at single-base resolution. Logo analysis of the sequence enrichment was performed by using WebLogo (http://weblogo.berkeley.edu/). Motif discovery was performed by using HOMER Motif Analysis (http://homer.salk.edu/homer/motif/). For CAPIP-seq only intragenic mapped reads were used for further analysis. RPKM of each genomic feature were calculated as described above by using custom script. Enrichment was calculated as the log fold change of RPKM value from CAP immunoprecipitated samples over the RPKM from input samples for each genomic feature. As for DECAP-seq, the intragenic CAPIP-seq signal ratio between wild-type and Dnmt3b−/− cells was calculated as the fold change of the intragenic enrichment (from 2 kb downstream TSS to TES) in wild-type over Dnmt3b−/− cells. The ratio gene-body to TSS was defined as the log fold change of gene-body enrichment (derived from intronic and intermediate exonic regions) over the enrichment calculated on the first 200 nt of the transcripts. All the analyses were performed on genes belonging to the third or fourth quartiles of expression. Poly(A)+ enriched RNA-seq analyses were performed from RNA derived from DRB-treated wild-type and Dnmt3b−/− ES cells. For half-life calculation, gene quantifications performed with CuffDiff (see above) were normalized on the average of the top ten genes showing less degradation rate following DRB treatment having at least 10 RPKM in ES cells. Degradation rate has been defined as the ratio of RPKM value of the sample at time 0 h of DRB treatment over the average RPKM value of the samples treated for 3, 6 and 12 h with DRB. The top ten genes are Tmsb10, Mt1, Mt2, Rps14, Rplp2, 4930412F15Rik, Rpl38, Rplp1, Tomm7 and Cox6a1. Only genes with a RPKM > 1 were used for further analysis and a constant of 0.1 pseudo-RPKM was introduced to reduce sampling noise. Half-life (t ) was calculated by using the following formula50: where k is the decay rate constant obtained by fitting data (gene RPKM value for each time point) with an exponential function. Half-life on introns was measured as calculated for mature mRNAs, but gene quantification (RPKM) was performed counting the reads on introns and normalizing for intron length (kb) and for the number of total intragenic mapped reads (millions). For introns and exons quantification, reads were treated as above (see RNA-seq analysis). Analysis of ART-seq experiments were performed as previously described31. Differently from the other sequencing data, for ribosome profiling, only adaptor containing reads were used in order to avoid total RNA contamination. Reads were clipped from adapters and mapped on rRNAs and tRNAs. Only reads not mapping on rRNA/tRNA genes were used for downstream analysis. Quantification (RPKM) of the reads derived from different transcript parts or genomic features was performed as described above. Following mapping, reads with the same start mapping coordinates were collapsed using custom Perl scripts, and peak calling was performed using MACS version 1.4.1 (ref. 51). ChIP-seq signal log enrichment was calculated as previously described10, with some modifications. In brief, the mouse genome was partitioned into 500-bp bins. Bins overlapping with satellite repeats and with an insufficient coverage in WGBS (less than 50% of all CpGs covered at least 10×) were removed resulting in 2,708,724 bins. Signal enrichment was calculated as the log of ChIP-seq over input RPKM. These whole-genome log enrichment values were used for clustering, correlation, box plot and scatter plot analysis by using custom scripts. For genomic binning by H3K36me3, the above bins were divided in ten equal-size groups rank-ordered by their log enrichment for H3K36me3. Heat map representations of ChIP-seq peaks and plots were performed with respect to annotated RefSeq genes, sorted by their expression level, according to RNA-seq data. Plots of Dnmt3b and H3K36me3 distribution on genes clustered in quartiles of expression revealed an almost identical distribution for both features. For the analysis of Dnmt3b intragenic binding in Setd2 knockdown ES cells and Dnmt3b-re-expressing Dnmt3b−/− ES cells, a non-redundant gene annotation was built starting from the RefFlat annotation, by keeping only the longest isoform for each gene. After calling H3K36me3 peaks in wild-type ES cells using MACS 1.4.1 (parameters: -p 1e-8 –nolambda), the genes from the RefFlat annotation that overlap an H3K36me3 peak were marked as H3K36me3-positive, while genes lacking any overlap were marked as H3K36me3-negative. For each gene in the two datasets, the normalized Dnmt3b signal (RPKM) in control and treated ES cells was calculated as: where n is the number of Dnmt3b reads overlapping a gene’s coordinates, TSS and TES are respectively the start and end coordinate of the gene annotation, and N is the total number of mapped reads in the ChIP-seq experiment. P values were calculated using a one-tailed paired Wilcoxon rank-sum test. Methylation calling was performed using the methratio.py script provided with the BSMAP tool and comparative analyses were performed by using only CpG covered at least 5× in both wild-type and Dnmt3b−/− cells. Heat maps and comparative analysis were performed using custom Perl scripts. Datasets used for comparative analysis were obtained from Gene Expression Omnibus by downloading the following datasets: GSE12241, GSE11172, GSE31039, GSE44642, GSE44566, GSE55660, GSE57413, GSE44566. Antibodies were purchased from Abcam (anti-Dnmt3b; anti-H3K36me3; anti-single-strand DNA; anti-H3 pan; anti-Tbp; anti-TIIb), from Imgenex (anti-Dnmt3a; anti-Dnmt3b; anti-Dnmt1), from Diagenode (anti-5-methylcytidine), from Millipore (anti-H3K27me3; anti-m3G-cap, anti-m7G-cap; anti-Elk1), from Upstate (anti-H3K4me3), from Covance (anti-Pol II-phospho-Ser5), from SantaCruz (anti-pan Pol II, anti-Sp1; anti-Elf1), from Upstate (anti-H3K4me3; anti-H3ac). Anti-Dnmt3l was provided by S. Yamanaka. The raw data that support the findings of this study have been deposited at Gene Expression Omnibus under the accession code GSE72856.


News Article | February 23, 2017
Site: globenewswire.com

HOUSTON, Feb. 22, 2017 (GLOBE NEWSWIRE) -- Targa Resources Partners LP (“Targa Resources Partners” or the “Partnership”) today announced that it has completed the 2016 tax packages for the following groups of unitholders, including Schedules K-1: The tax packages are available online by accessing the Partnership's website at www.targaresources.com, and the Partnership expects to complete the tax package mailing by Friday, February 24, 2017. A link to K-1 Tax Support is located at the top right of the page.  The tax packages can also be accessed directly at: https://www.partnerdatalink.com/Targa/. Changes to tax packages for Targa Resources Partners LP common units can be (i) made via either of the websites shown above, (ii) submitted by email to TargaK1Help@deloitte.com, (iii) faxed to (215) 982-6302, (iv) directed to the Partnership's K-1 call center at (877) 742-0133, or (v) mailed to: Similarly, changes to tax packages for Targa Resources Partners LP Series A Preferred Units can be (i) made by clicking https://www.PartnerDataLink.com/TargaPrefA or www.targaresources.com, (ii) submitted by email to TargaPreferredAK1Help@deloitte.com, (iii) faxed to (215) 982-6302, (iv) directed to the Partnership’s K-1 call center at (844) 435-5150, or (v) mailed to the post office box shown above. Targa Resources Corp. is a leading provider of midstream services and is one of the largest independent midstream energy companies in North America. TRC owns, operates, acquires, and develops a diversified portfolio of complementary midstream energy assets. The Company is primarily engaged in the business of: gathering, compressing, treating, processing, and selling natural gas; storing, fractionating, treating, transporting, and selling NGLs and NGL products, including services to LPG exporters; gathering, storing, and terminaling crude oil; storing, terminaling, and selling refined petroleum products. The principal executive offices of Targa are located at 1000 Louisiana, Suite 4300, Houston, TX 77002 and their telephone number is 713-584-1000.  For more information please go to www.targaresources.com.


News Article | February 23, 2017
Site: globenewswire.com

HOUSTON, Feb. 22, 2017 (GLOBE NEWSWIRE) -- Targa Resources Partners LP (“Targa Resources Partners” or the “Partnership”) today announced that it has completed the 2016 tax packages for the following groups of unitholders, including Schedules K-1: The tax packages are available online by accessing the Partnership's website at www.targaresources.com, and the Partnership expects to complete the tax package mailing by Friday, February 24, 2017. A link to K-1 Tax Support is located at the top right of the page.  The tax packages can also be accessed directly at: https://www.partnerdatalink.com/Targa/. Changes to tax packages for Targa Resources Partners LP common units can be (i) made via either of the websites shown above, (ii) submitted by email to TargaK1Help@deloitte.com, (iii) faxed to (215) 982-6302, (iv) directed to the Partnership's K-1 call center at (877) 742-0133, or (v) mailed to: Similarly, changes to tax packages for Targa Resources Partners LP Series A Preferred Units can be (i) made by clicking https://www.PartnerDataLink.com/TargaPrefA or www.targaresources.com, (ii) submitted by email to TargaPreferredAK1Help@deloitte.com, (iii) faxed to (215) 982-6302, (iv) directed to the Partnership’s K-1 call center at (844) 435-5150, or (v) mailed to the post office box shown above. Targa Resources Corp. is a leading provider of midstream services and is one of the largest independent midstream energy companies in North America. TRC owns, operates, acquires, and develops a diversified portfolio of complementary midstream energy assets. The Company is primarily engaged in the business of: gathering, compressing, treating, processing, and selling natural gas; storing, fractionating, treating, transporting, and selling NGLs and NGL products, including services to LPG exporters; gathering, storing, and terminaling crude oil; storing, terminaling, and selling refined petroleum products. The principal executive offices of Targa are located at 1000 Louisiana, Suite 4300, Houston, TX 77002 and their telephone number is 713-584-1000.  For more information please go to www.targaresources.com.


News Article | February 23, 2017
Site: globenewswire.com

HOUSTON, Feb. 22, 2017 (GLOBE NEWSWIRE) -- Targa Resources Partners LP (“Targa Resources Partners” or the “Partnership”) today announced that it has completed the 2016 tax packages for the following groups of unitholders, including Schedules K-1: The tax packages are available online by accessing the Partnership's website at www.targaresources.com, and the Partnership expects to complete the tax package mailing by Friday, February 24, 2017. A link to K-1 Tax Support is located at the top right of the page.  The tax packages can also be accessed directly at: https://www.partnerdatalink.com/Targa/. Changes to tax packages for Targa Resources Partners LP common units can be (i) made via either of the websites shown above, (ii) submitted by email to TargaK1Help@deloitte.com, (iii) faxed to (215) 982-6302, (iv) directed to the Partnership's K-1 call center at (877) 742-0133, or (v) mailed to: Similarly, changes to tax packages for Targa Resources Partners LP Series A Preferred Units can be (i) made by clicking https://www.PartnerDataLink.com/TargaPrefA or www.targaresources.com, (ii) submitted by email to TargaPreferredAK1Help@deloitte.com, (iii) faxed to (215) 982-6302, (iv) directed to the Partnership’s K-1 call center at (844) 435-5150, or (v) mailed to the post office box shown above. Targa Resources Corp. is a leading provider of midstream services and is one of the largest independent midstream energy companies in North America. TRC owns, operates, acquires, and develops a diversified portfolio of complementary midstream energy assets. The Company is primarily engaged in the business of: gathering, compressing, treating, processing, and selling natural gas; storing, fractionating, treating, transporting, and selling NGLs and NGL products, including services to LPG exporters; gathering, storing, and terminaling crude oil; storing, terminaling, and selling refined petroleum products. The principal executive offices of Targa are located at 1000 Louisiana, Suite 4300, Houston, TX 77002 and their telephone number is 713-584-1000.  For more information please go to www.targaresources.com.


News Article | February 23, 2017
Site: globenewswire.com

HOUSTON, Feb. 22, 2017 (GLOBE NEWSWIRE) -- Targa Resources Partners LP (“Targa Resources Partners” or the “Partnership”) today announced that it has completed the 2016 tax packages for the following groups of unitholders, including Schedules K-1: The tax packages are available online by accessing the Partnership's website at www.targaresources.com, and the Partnership expects to complete the tax package mailing by Friday, February 24, 2017. A link to K-1 Tax Support is located at the top right of the page.  The tax packages can also be accessed directly at: https://www.partnerdatalink.com/Targa/. Changes to tax packages for Targa Resources Partners LP common units can be (i) made via either of the websites shown above, (ii) submitted by email to TargaK1Help@deloitte.com, (iii) faxed to (215) 982-6302, (iv) directed to the Partnership's K-1 call center at (877) 742-0133, or (v) mailed to: Similarly, changes to tax packages for Targa Resources Partners LP Series A Preferred Units can be (i) made by clicking https://www.PartnerDataLink.com/TargaPrefA or www.targaresources.com, (ii) submitted by email to TargaPreferredAK1Help@deloitte.com, (iii) faxed to (215) 982-6302, (iv) directed to the Partnership’s K-1 call center at (844) 435-5150, or (v) mailed to the post office box shown above. Targa Resources Corp. is a leading provider of midstream services and is one of the largest independent midstream energy companies in North America. TRC owns, operates, acquires, and develops a diversified portfolio of complementary midstream energy assets. The Company is primarily engaged in the business of: gathering, compressing, treating, processing, and selling natural gas; storing, fractionating, treating, transporting, and selling NGLs and NGL products, including services to LPG exporters; gathering, storing, and terminaling crude oil; storing, terminaling, and selling refined petroleum products. The principal executive offices of Targa are located at 1000 Louisiana, Suite 4300, Houston, TX 77002 and their telephone number is 713-584-1000.  For more information please go to www.targaresources.com.


News Article | March 2, 2017
Site: www.prnewswire.com

FORT WASHINGTON, Pa., March 2, 2017 /PRNewswire-USNewswire/ -- Thermostat Recycling Corporation (TRC) is pleased to announce Franklin Energy Services as its March collection partner for the state of Illinois. With over two decades in the energy efficiency landscape, Franklin Energy...

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