UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of Report (Date of earliest event reported): August 6, 2012
TARGA RESOURCES CORP.
(Exact name of registrant as specified in its charter)
| Delaware | 001-34991 | 20-3701075 | ||
| (State or other jurisdiction of incorporation or organization) |
(Commission File Number) |
(IRS Employer Identification No.) |
1000 Louisiana, Suite 4300
Houston, TX 77002
(Address of principal executive office and Zip Code)
(713) 584-1000
(Registrants’ telephone number, including area code)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
| ¨ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
| ¨ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
| ¨ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
| ¨ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
| Item 2.02 | Results of Operations and Financial Condition. |
On August 6, 2012 Targa Resources Corp. (the “Company”) issued a press release regarding its financial results for the three and six months ended June 30, 2012. A conference call to discuss these results is scheduled for 10:30 a.m. Eastern time on Monday, August 6, 2012. The conference call will be webcast live and a replay of the webcast will be available through the Investors section of the Company’s web site (http://www.targaresources.com) until August 20, 2012. A copy of the earnings press release is furnished as Exhibit 99.1 to this report, which is hereby incorporated by reference into this Item 2.02.
The press release and accompanying schedules and/or the conference call discussions include the non-generally accepted accounting principles (“non-GAAP”) financial measures of distributable cash flow, gross margin, operating margin and Adjusted EBITDA. The press release provides reconciliations of these non-GAAP financial measures to their most directly comparable financial measure calculated and presented in accordance with generally accepted accounting principles in the United States of America (“GAAP”). Our non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net cash provided by operating activities, net income (loss) or any other GAAP measure of liquidity or financial performance.
| Item 9.01 | Financial Statements and Exhibits. |
(d) Exhibits
| Exhibit |
Description | |
| Exhibit 99.1 | Targa Resources Corp. Press Release dated August 6, 2012. |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| TARGA RESOURCES CORP. | ||||
| Dated: August 6, 2012 | By: | /s/ Matthew J. Meloy | ||
| Matthew J. Meloy | ||||
| Senior Vice President, Chief Financial Officer and Treasurer | ||||
EXHIBIT INDEX
| Exhibit |
Description | |
| Exhibit 99.1 | Targa Resources Corp. Press Release dated August 6, 2012. |
Exhibit 99.1
Targa Resources Partners LP and Targa Resources Corp. Report
Second Quarter 2012 Financial Results
HOUSTON—August 6, 2012—Targa Resources Partners LP (NYSE: NGLS) (“Targa Resources Partners” or the “Partnership”) and Targa Resources Corp. (NYSE: TRGP) (“TRC” or the “Company”) today reported second quarter 2012 results. Second quarter 2012 net income attributable to Targa Resources Partners was $46.8 million compared to $55.2 million for the second quarter of 2011. The income per diluted limited partner unit was $0.35 in the second quarter of 2012 compared to $0.55 for the second quarter of 2011. The Partnership reported earnings before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments (“Adjusted EBITDA”) of $122.9 million for the second quarter of 2012 compared to $129.8 million for the second quarter of 2011.
The Partnership’s distributable cash flow for the second quarter 2012 of $84.5 million corresponds to distribution coverage of approximately 1.15 times the $73.2 million in total distributions to be paid on August 14, 2012 (see the section of this release entitled “Targa Resources Partners—Non-GAAP Financial Measures” for a discussion of Adjusted EBITDA, gross margin, operating margin and distributable cash flow, 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”)).
“The Partnership reported second quarter 2012 Adjusted EBITDA of $123 million, performing well against the backdrop of weaker commodity prices,” said Joe Bob Perkins, CEO of the general partner of the Partnership and of Targa Resources Corp. “We expect the impact from our growth projects, which are primarily fee-based, to provide the margin, scale and diversity that will support continued distribution growth even in the current price environment.”
On July 11, 2012, the Partnership announced a cash distribution for the second quarter 2012 of 64.25¢ per common unit, or $2.57 per unit on an annualized basis, representing an increase of approximately 3% over the first quarter 2012 and 13% over the distribution for the second quarter 2011. The cash distribution will be paid on August 14, 2012 on all outstanding common units to holders of record as of the close of business on July 23, 2012. The total distribution paid will be $73.2 million, with $49.0 million to the Partnership’s third-party limited partners, and $24.2 million to TRC for its ownership of common units, incentive distribution rights (“IDRs”) and its 2% general partner interest in the Partnership.
Targa Resources Partners—Capitalization, Liquidity and Financing Update
Total funded debt at the Partnership as of June 30, 2012 was $1,521.0 million including $140.0 million outstanding under the Partnership’s $1.1 billion senior secured revolving credit facility, $209.1 million of 8 1/4% senior unsecured notes due 2016, $72.7 million of 11 1/4% senior unsecured notes due 2017, $250.0 million of 7 7/8% senior unsecured notes due 2018, $483.6 million of 6 7/8% senior unsecured notes due 2021, $400.0 million of 6 3/8% senior unsecured notes due 2022, and $34.4 million of unamortized discounts.
As of June 30, 2012, after giving effect to $70.2 million in outstanding letters of credit, the Partnership had available revolver capacity of $889.8 million and $89.5 million of cash resulting in total liquidity of $979.3 million.
For 2012, the Partnership continues to expect total capital expenditures will be $680 million gross and $650 million net of noncontrolling interest share and reimbursements. Maintenance capital expenditures are expected to be approximately 12% of the total net capital expenditures.
Targa Resources Corp.—Second Quarter 2012 Financial Results
Targa Resources Corp., the parent of Targa Resources Partners, reported its second quarter 2012 results. The Company, which at June 30, 2012 owned a 2% general partner interest (held through its 100% ownership interest in the general partner of the Partnership), all of the IDRs and 12,945,659 common units of the Partnership, presents its results consolidated with those of the Partnership.
TRC reported net income available to common shareholders of $8.6 million for the second quarter 2012 compared with a net income available to common shareholders of $10.5 million for the second quarter 2011. The net income per diluted common share was $0.21 in the second quarter of 2012 compared to $0.25 for the second quarter of 2011.
Second quarter 2012 distributions to be paid on August 14, 2012 by the Partnership to the Company will be $24.2 million, with $8.3 million, $14.4 million and $1.5 million paid with respect to common units, IDRs and general partner interests, respectively. On July 11, 2012, TRC declared a quarterly dividend of 39.375¢ per share of its common stock for the three months ended June 30, 2012, or $1.575 per share on an annualized basis, representing increases of approximately 8% over the previous quarter’s dividend and 36% over the dividend for the second quarter of 2011. Total cash dividends declared of approximately $16.1 million will be paid August 15, 2012 on all outstanding common shares to holders of record as of the close of business on July 23, 2012.
The Company’s distributable cash flow for the second quarter 2012 of $17.3 million corresponds to dividend coverage of approximately 1.04 times the $16.7 million in total declared dividends for the quarter (see the section of this release entitled “Targa Resources Corp.—Non-GAAP Financial Measures” for a discussion of distributable cash flow and reconciliations of this measure to its most directly comparable financial measure calculated and presented in accordance with GAAP).
Targa Resources Corp.—Capitalization, Liquidity and Financing Update
Total funded debt of the Company as of June 30, 2012, excluding debt of the Partnership, was $89.3 million. The Company also has access to the full amount of its $75.0 million senior secured revolving credit facility due 2014.
The Company’s cash balance, excluding cash held at the Partnership and its subsidiaries, was $28 million as of June 30, 2012, resulting in total liquidity of $103 million.
Conference Call
Targa Resources Partners and Targa Resources Corp. will host a joint conference call for investors and analysts at 10:30 a.m. Eastern Time (9:30 a.m. Central Time) on August 6, 2012 to discuss second quarter 2012 financial results. The conference call can be accessed via Webcast through the Events and Presentations section of the Partnership’s and the Company’s website at www.targaresources.com, by going directly to http://ir.targaresources.com/events.cfm?company=LP or by dialing 877-881-2598. The pass code for the dial-in is 11276679. Please dial in ten minutes prior to the scheduled start time. A replay will be available approximately two hours following completion of the Webcast through the Investor’s section of the Partnership’s and the Company’s website. Telephone replay access numbers are 855-859-2056 or 404-537-3406 with pass code 11276679 and will remain available, along with the Webcast, until August 20, 2012.
Targa Resources Partners – Consolidated Financial Results of Operations
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| (In millions except per unit data) | ||||||||||||||||
| Revenues |
$ | 1,318.4 | $ | 1,726.0 | $ | 2,963.9 | $ | 3,341.1 | ||||||||
| Product purchases |
1,074.6 | 1,477.8 | 2,458.7 | 2,879.0 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Gross margin (1) |
243.8 | 248.2 | 505.2 | 462.1 | ||||||||||||
| Operating expenses |
77.2 | 71.6 | 148.8 | 137.6 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating margin (2) |
166.6 | 176.6 | 356.4 | 324.5 | ||||||||||||
| Depreciation and amortization expense |
47.6 | 44.5 | 94.3 | 87.2 | ||||||||||||
| General and administrative expense |
33.5 | 33.2 | 66.4 | 64.9 | ||||||||||||
| Other operating |
— | — | (0.1 | ) | — | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Income from operations |
85.5 | 98.9 | 195.8 | 172.4 | ||||||||||||
| Interest expense, net |
(29.4 | ) | (27.2 | ) | (58.8 | ) | (54.6 | ) | ||||||||
| Equity in earnings of unconsolidated investment |
(0.2 | ) | 1.3 | 1.9 | 3.0 | |||||||||||
| Loss on mark-to-market derivative instruments |
— | (3.2 | ) | — | (3.2 | ) | ||||||||||
| Other |
(0.4 | ) | 0.1 | (0.5 | ) | (0.1 | ) | |||||||||
| Income tax expense |
(0.8 | ) | (1.9 | ) | (1.8 | ) | (3.7 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income |
54.7 | 68.0 | 136.6 | 113.8 | ||||||||||||
| Less: Net income attributable to noncontrolling interest |
7.9 | 12.8 | 19.6 | 20.7 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income attributable to Targa Resources Partners LP |
$ | 46.8 | $ | 55.2 | $ | 117.0 | $ | 93.1 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income attributable to general partner |
15.4 | 8.9 | 29.5 | 16.5 | ||||||||||||
| Net income attributable to limited partners |
31.4 | 46.3 | 87.5 | 76.6 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income attributable to Targa Resources Partners LP |
$ | 46.8 | $ | 55.2 | $ | 117.0 | $ | 93.1 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Basic net income per limited partner unit |
$ | 0.35 | $ | 0.55 | $ | 0.99 | $ | 0.92 | ||||||||
| Diluted net income per limited partner unit |
0.35 | 0.55 | 0.99 | 0.92 | ||||||||||||
| Financial data: |
||||||||||||||||
| Adjusted EBITDA (3) |
$ | 122.9 | $ | 129.8 | $ | 268.3 | $ | 237.2 | ||||||||
| Distributable cash flow (4) |
84.5 | 90.0 | 190.2 | 164.1 | ||||||||||||
| Operating data: |
||||||||||||||||
| Plant natural gas inlet, MMcf/d (5)(6) |
2,083.0 | 2,203.6 | 2,157.8 | 2,186.2 | ||||||||||||
| Gross NGL production, MBbl/d |
124.0 | 126.1 | 128.1 | 122.6 | ||||||||||||
| Natural gas sales, BBtu/d (6) |
930.3 | 756.3 | 895.4 | 719.6 | ||||||||||||
| NGL sales, MBbl/d |
270.3 | 261.0 | 274.7 | 268.3 | ||||||||||||
| Condensate sales, MBbl/d |
3.7 | 3.7 | 3.4 | 3.1 | ||||||||||||
| (1) | Gross margin is a non-GAAP financial measure and is discussed under “Targa Resources Partners – Non-GAAP Financial Measures.” |
| (2) | Operating margin is a non-GAAP financial measure and is discussed under “Targa Resources Partners – Non-GAAP Financial Measures.” |
| (3) | Adjusted EBITDA is net income before interest, income taxes, depreciation and amortization, gains or losses on debt repurchases and non-cash risk management activities related to derivative instruments. This is a non-GAAP financial measure and is discussed under “Targa Resources Partners – Non-GAAP Financial Measures.” |
| (4) | Distributable cash flow is net income attributable to Targa Resources Partners LP plus depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for losses (gains) on mark-to-market derivative contracts and debt repurchases, less maintenance capital expenditures (net of any reimbursements of project costs). This is a non-GAAP financial measure and is discussed under “Targa Resources Partners – Non-GAAP Financial Measures.” |
| (5) | Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant. |
| (6) | Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes. |
Targa Resources Partners – Review of Consolidated Second Quarter Results
Three Months Ended June 30, 2012 Compared to Three Months Ended June 30, 2011
Revenues, including the impacts of hedging, decreased due to the impact of lower realized prices on all commodities ($592.4 million), partially offset by higher commodity sales volumes ($115.1 million) and higher fee-based and other revenues ($69.7 million).
The decrease in operating margin reflects a lower gross margin, as well as higher operating expenses. The decrease in gross margin resulted from lower revenues ($407.6 million) offset by lower product purchase costs that also reflect the lower commodity price environment ($403.2 million). The increase in operating expenses primarily reflects increased compensation and benefits and contractor costs related to expanded business operations and acquisitions. See “Targa Resources Partners – Review of Segment Performance” for additional information regarding changes in the components of operating margin on a disaggregated basis.
The increase in depreciation and amortization expenses was primarily due to the impact of assets placed in service in 2011.
General and administrative expenses increased primarily due to higher compensation and benefits.
The increase in interest expense was the result of higher borrowings ($4.6 million) partially offset by higher capitalized interest ($2.4 million).
During the second quarter of 2012, Gulf Coast Fractionators, in which we have an equity investment, executed a planned shutdown and turnaround of operations during which construction and facility modifications associated with a 43 MBbl/d capacity expansion were completed. This resulted in a loss for the quarter from this equity investment.
The mark-to-market loss in 2011 is attributable to interest rate swaps that were de-designated during the second quarter of that year. Consequently, we discontinued hedge accounting on those swaps, so changes in fair value and cash settlements were recorded as mark-to-market loss. We terminated all of our interest rate swaps in September 2011.
The decrease in net income attributable to noncontrolling interests reflects the impact of the weaker price environment on the earnings of our non-wholly owned consolidated subsidiaries.
Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011
Revenues, including the impacts of hedging, decreased due to the impact of lower realized prices on all commodities ($739.1 million), partially offset by higher commodity sales volumes ($220.2 million) and higher fee-based and other revenues ($141.7 million).
The increase in operating margin reflects higher gross margin, partially offset by higher operating expenses. The increase in gross margin resulted from lower revenues ($377.2 million) offset by lower product purchase costs ($420.3 million). The increase in operating expenses primarily reflects increased compensation and benefits and contractor costs related to expanded business operations and acquisitions. See “Targa Resources Partners – Review of Segment Performance” for additional information regarding changes in the components of operating margin on a disaggregated basis.
The increase in depreciation and amortization expenses was primarily due to the impact of assets placed in service in 2011.
General and administrative expenses increased primarily due to higher compensation and benefits.
The increase in interest expense was primarily the result of higher borrowings ($6.8 million) partially offset by higher capitalized interest ($3.3 million).
Mark-to-market loss for the year-to-date period of 2012 compared to 2011 is explained above for the three months ended June 30.
The decrease in net income attributable to noncontrolling interests reflects the impact of lower earnings at our non-wholly owned consolidated subsidiaries.
Targa Resources Partners – Review of Segment Performance
The following discussion of segment performance includes inter-segment revenues. The Partnership 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 Partners—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 for the period and the denominator is the number of calendar days for the period.
The Partnership reports its operations in two divisions: (i) Natural Gas Gathering and Processing, consisting of two reportable segments—(a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing, consisting of two reportable segments—(a) Logistics Assets and (b) Marketing and Distribution. The financial results of the Partnership’s commodity hedging activities are reported in Other.
Natural Gas Gathering and Processing Segments
Field Gathering and Processing
The Field Gathering and Processing segment gathers and processes natural gas from the Permian Basin in West Texas and Southeast New Mexico and the Fort Worth Basin, including the Barnett Shale, in North Texas. The segment’s processing plants include nine owned and operated facilities.
The following table provides summary data regarding results of operations of this segment for the periods indicated:
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| ($ in millions) | ||||||||||||||||
| Gross margin |
$ | 85.0 | $ | 109.1 | $ | 187.3 | $ | 197.0 | ||||||||
| Operating expenses |
31.1 | 28.9 | 60.4 | 55.7 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating margin |
$ | 53.9 | $ | 80.2 | $ | 126.9 | $ | 141.3 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating statistics (1): |
||||||||||||||||
| Plant natural gas inlet, MMcf/d (2), (3) |
||||||||||||||||
| Permian |
130.6 | 132.2 | 138.2 | 127.5 | ||||||||||||
| SAOU |
121.9 | 108.5 | 118.6 | 107.8 | ||||||||||||
| North Texas System |
242.6 | 196.8 | 233.5 | 190.7 | ||||||||||||
| Versado |
169.9 | 174.1 | 169.9 | 166.3 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| 665.1 | 611.7 | 660.2 | 592.4 | |||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Gross NGL production, MBbl/d |
||||||||||||||||
| Permian |
15.4 | 15.2 | 16.2 | 14.9 | ||||||||||||
| SAOU |
18.9 | 17.1 | 18.5 | 16.8 | ||||||||||||
| North Texas System |
26.8 | 22.8 | 25.8 | 21.9 | ||||||||||||
| Versado |
20.0 | 19.4 | 19.5 | 18.4 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| 81.1 | 74.6 | 80.1 | 72.0 | |||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Natural gas sales, BBtu/d (3) |
312.6 | 284.4 | 313.0 | 273.8 | ||||||||||||
| NGL sales, MBbl/d |
67.5 | 59.9 | 66.2 | 58.2 | ||||||||||||
| Condensate sales, MBbl/d |
3.5 | 3.4 | 3.2 | 2.8 | ||||||||||||
| Average realized prices (4): |
||||||||||||||||
| Natural gas, $/MMBtu |
2.02 | 4.04 | 2.29 | 3.92 | ||||||||||||
| NGL, $/gal |
0.86 | 1.24 | 0.96 | 1.18 | ||||||||||||
| Condensate, $/Bbl |
86.51 | 98.13 | 92.34 | 95.27 | ||||||||||||
| (1) | Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter. |
| (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. |
| (3) | Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes. |
| (4) | Average realized prices exclude the impact of hedging activities presented in Other. |
Three Months Ended June 30, 2012 Compared to Three Months Ended June 30, 2011
The decrease in gross margin was primarily due to lower natural gas, NGL and condensate sales prices partially offset by higher throughput volumes. The increase in plant inlet volumes was largely attributable to new well connects, particularly North Texas, Sand Hills and SAOU partially offset by pipeline curtailments and operational issues.
The increase in operating expenses was primarily due to additional compression related expenses due to system expansions and higher system maintenance and repair costs.
Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011
Results for the year-to-date period of 2012 compared to 2011 reflect the same factors as described above for the three months ended June 30. Additionally, the negative impact of severe cold weather and operational outages in the first quarter of 2011 exceeded the negative impact of pipeline curtailments and operational issues in the first and second quarters of 2012.
Coastal Gathering and Processing
The Coastal Gathering and Processing segment assets are located in the onshore and near offshore region of the Louisiana Gulf Coast and the Gulf of Mexico. With the strategic location of the Partnership’s assets in Louisiana, it has access to the Henry Hub, the largest natural gas hub in the U.S., and a substantial NGL distribution system with access to markets throughout Louisiana and the Southeast United States.
The following table provides summary data regarding results of operations of this segment for the periods indicated:
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| ($ in millions except price data) | ||||||||||||||||
| Gross margin |
$ | 38.8 | $ | 57.1 | $ | 95.5 | $ | 103.6 | ||||||||
| Operating expenses |
10.8 | 11.4 | 21.2 | 21.6 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating margin |
$ | 28.0 | $ | 45.7 | $ | 74.3 | $ | 82.0 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating statistics (1): |
||||||||||||||||
| Plant natural gas inlet, MMcf/d (2),(3) |
||||||||||||||||
| LOU |
214.7 | 164.6 | 204.8 | 168.8 | ||||||||||||
| Coastal Straddles |
760.9 | 923.0 | 800.2 | 933.2 | ||||||||||||
| VESCO |
442.3 | 504.3 | 492.6 | 491.9 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| 1,417.9 | 1,591.9 | 1,497.6 | 1,593.9 | |||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Gross NGL production, MBbl/d |
||||||||||||||||
| LOU |
8.2 | 6.5 | 8.2 | 6.7 | ||||||||||||
| Coastal Straddles |
15.8 | 18.0 | 16.7 | 17.6 | ||||||||||||
| VESCO |
18.8 | 27.0 | 23.2 | 26.3 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| 42.9 | 51.5 | 48.0 | 50.6 | |||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Natural gas sales, Bbtu/d (3) |
315.1 | 272.0 | 298.5 | 263.3 | ||||||||||||
| NGL sales, MBbl/d |
40.7 | 43.8 | 44.0 | 43.7 | ||||||||||||
| Condensate sales, MBbl/d |
0.2 | 0.3 | 0.2 | 0.3 | ||||||||||||
| Average realized prices (4): |
||||||||||||||||
| Natural gas, $/MMBtu |
2.27 | 4.35 | 2.43 | 4.25 | ||||||||||||
| NGL, $/gal |
0.95 | 1.34 | 1.06 | 1.27 | ||||||||||||
| Condensate, $/Bbl |
91.40 | 109.05 | 111.64 | 100.51 | ||||||||||||
| (1) | Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter. |
| (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. |
| (3) | Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes. |
| (4) | Average realized prices exclude the impact of hedging activities presented in Other. |
Three Months Ended June 30, 2012 Compared to Three Months Ended June 30, 2011
The decrease in gross margin was primarily due to lower commodity sales prices, less favorable frac spread and lower throughput volumes. The decrease in plant inlet volumes was largely attributable to the decline in offshore and off-system supply volumes, and planned operational outages at VESCO, partially offset by increased traditional wellhead volumes at LOU and gas purchased for processing at VESCO and Lowry. Increased NGL production and sales at LOU and the continued optimization of Straddle plants throughput to more efficient, higher recovery plants reduced the impact of the total lower throughput volumes on NGL production and sales volumes. Natural gas sales volumes increased due to an increase in demand from industrial customers and increased sales to other reportable segments for resale.
The decrease in operating expenses was primarily due to lower utilities, power and catalysts costs and higher refunds of operating expenses after ownership adjustments at non-operated joint ventures, partially offset by higher system maintenance and repair costs.
Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011
Other than a higher commodity sales price for condensate, the results for the year-to-date period of 2012 compared to 2011 reflect the same factors as described above for the three months ended June 30.
Logistics and Marketing Segments
Logistics Assets
The Logistics Assets segment is involved in transporting, storing and fractionating mixed NGLs; storing, terminaling and transporting finished NGLs; and storing and terminaling refined petroleum products and crude oil. The Partnership’s logistics assets are generally connected to, and supplied in part by, its Natural Gas Gathering and Processing segments and are predominantly located at Mont Belvieu, Texas and Southwestern Louisiana. This segment also includes the activities associated with the 2011 acquisitions of refined petroleum products and crude oil storage and terminaling facilities.
The following table provides summary data regarding results of operations of this segment for the periods indicated:
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| ($ in millions, except price data) | ||||||||||||||||
| Gross margin |
$ | 69.1 | $ | 56.9 | $ | 133.5 | $ | 99.3 | ||||||||
| Operating expenses |
23.4 | 23.5 | 44.8 | 43.6 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating margin |
$ | 45.7 | $ | 33.4 | $ | 88.7 | $ | 55.7 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating statistics (1): |
||||||||||||||||
| Fractionation volumes, MBbl/d |
311.3 | 279.7 | 302.5 | 244.7 | ||||||||||||
| LSNG Treating volumes, MBbl/d (2) |
27.1 | 27.8 | 23.1 | 19.1 | ||||||||||||
| (1) | Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter. |
| (2) | Includes the volumes related to the natural gasoline hydrotreater at our Mt. Belvieu facility. |
Three Months Ended June 30, 2012 Compared to Three Months Ended June 30, 2011
Operating margins increased significantly due to the favorable impacts of fractionation capacity expansions, additional treating capabilities and the growth of our other logistics operations. Gross margin improvements include higher fractionation fees associated with the Cedar Bayou facility Train 3 expansion which came on line mid-year 2011 (partially offset by the impact of lower fuel prices which pass through to expenses), increased treating fees associated with the operational startup of the benzene treating unit in the first quarter of 2012, increased exports and the impact of the 2011 petroleum logistics acquisitions.
While operating expenses were essentially flat, the increase in operating costs associated with the petroleum logistics terminals acquired after the second quarter of 2011 and increased non-fuel operating expenses related to facility expansions were offset by lower fuel costs (which have a corresponding impact on revenues) and by favorable system product gains.
Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011
The increase in gross margin was primarily due to higher fractionation and treating fees, increased exports and the impact of the 2011 petroleum logistics acquisitions. Higher fractionation volumes and fees were primarily attributable to the Cedar Bayou facility Train 3 expansion which came on line in mid-year 2011 (partially offset by the impact of lower fuel prices which pass through to expenses). Treating fees increased due to the operational startup of the benzene treating unit in the first quarter of 2012.
The increase in operating expenses was primarily due to the operating costs of the petroleum logistics terminals acquired after the second quarter of 2011. Increases in non-fuel operating expenses related to facility expansions were offset by lower fuel costs (which have a corresponding impact on revenues) and by favorable system product gains.
Marketing and Distribution
The Marketing and Distribution segment covers all activities required to distribute and market raw and finished natural gas liquids and all natural gas marketing activities. It includes: (1) marketing of the Partnership’s natural gas liquids production and purchasing natural gas liquids products in selected United States markets; (2) providing liquefied petroleum gas balancing services to refinery customers; (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end users; and (4) marketing natural gas available to the Partnership from its Natural Gas Gathering and Processing division and the purchase and resale of natural gas in selected United States markets.
The following table provides summary data regarding results of operations of this segment for the periods indicated:
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| ($ in millions) | ||||||||||||||||
| Gross margin |
$ | 35.4 | $ | 41.4 | $ | 70.8 | $ | 85.9 | ||||||||
| Operating expenses |
9.2 | 10.9 | 18.4 | 22.8 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating margin |
$ | 26.2 | $ | 30.5 | $ | 52.4 | $ | 63.1 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating statistics (1): |
||||||||||||||||
| Natural gas sales, BBtu/d |
1,096.1 | 857.5 | 1,059.8 | 761.4 | ||||||||||||
| NGL sales, MBbl/d |
274.4 | 265.0 | 278.5 | 268.7 | ||||||||||||
| Average realized prices: |
||||||||||||||||
| Natural gas, $/MMBtu |
2.21 | 4.28 | 2.40 | 4.19 | ||||||||||||
| NGL realized price, $/gal |
0.92 | 1.35 | 1.07 | 1.31 | ||||||||||||
| (1) | Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter. |
Three Months Ended June 30, 2012 Compared to Three Months Ended June 30, 2011
The decrease in gross margin was primarily due to a weaker price environment compared to last year partially offset by increased LPG export activity and by short-term distribution opportunities resulting from supply and market conditions. Export cargo shipments increased by approximately 80% and export margins were higher compared to the same period last year. As in 2011, gross margin benefitted from receipt of a contract settlement payment related to a multi-year propane exchange agreement ($3.8 million received in 2Q 2012 versus $7.5 million in 2011). The contract, as restructured, may result in the receipt of future payments over the remaining term of the contract.
The decrease in operating expenses was primarily due to a decrease in barge activity from the same period last year.
Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011
Results for the year-to-date period of 2012 compared to 2011 reflect substantially the same factors as described above for the three months ended June 30 with export cargo shipments increased by 100%.
Other
Other contains the financial effects of the Partnership’s hedging program on operating margin. It typically represents the cash settlements on the Partnership’s derivative contracts. Other also includes deferred gains or losses on previously terminated or de-designated hedge contracts that are reclassified to revenues upon the occurrence of the underlying physical transactions.
The primary purpose of our commodity risk management activities is to manage the Partnership’s exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. The Partnership has hedged the commodity price associated with a portion of its expected natural gas, NGL and condensate equity volumes by entering into derivative instruments. Because the Partnership is essentially forward selling a portion of its plant equity volumes, these hedge positions will move favorably in periods of falling prices and unfavorably in periods of rising prices.
Three Months Ended June 30, 2012 Compared to Three Months Ended June 30, 2011
For the three months ended June 30, 2012, the Partnership’s cash flow hedging program increased gross margin by $12.8 million compared to a decrease of $13.2 million for the same period in 2011. The increase was driven by lower natural gas and NGL prices.
Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011
For the six months ended June 30, 2012, the Partnership’s cash flow hedging program increased gross margin by $14.1 million compared to a decrease of $17.6 million for the same period in 2011. The increase was driven by lower natural gas and NGL prices.
About Targa Resources Corp. and Targa Resources Partners
Targa Resources Corp. is a publicly traded Delaware corporation that owns a 2% general partner interest (which the Company holds through its 100% ownership interest in the general partner of the Partnership), all of the outstanding incentive distribution rights and a portion of the outstanding limited partner interests in Targa Resources Partners LP.
Targa Resources Partners is a publicly traded Delaware limited partnership that is a leading provider of midstream natural gas and natural gas liquid services in the United States. The Partnership is engaged in the business of gathering, compressing, treating, processing and selling natural gas; storing, fractionating, treating, transporting and selling natural gas liquids, or NGLs, and NGL products; and storing and terminaling refined petroleum products and crude oil. The Partnership owns an extensive network of integrated gathering pipelines and gas processing plants and currently operates along the Louisiana Gulf Coast primarily accessing the onshore and near offshore region of Louisiana, the Permian Basin in West Texas and Southeast New Mexico and the Fort Worth Basin in North Texas. Additionally, the Partnership’s logistics and marketing assets are located primarily at Mont Belvieu and Galena Park near Houston, Texas and in Lake Charles, Louisiana with terminals and transportation assets across the United States. Targa Resources Partners is managed by its general partner, Targa Resources GP LLC, which is indirectly wholly owned by Targa Resources Corp.
The principal executive offices of Targa Resources Corp. and Targa Resources Partners 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.
Targa Resources Partners—Non-GAAP Financial Measures
This press release includes the Partnership’s non-GAAP financial measures distributable cash flow, Adjusted EBITDA, gross margin and operating margin. The following tables provide reconciliations of these non-GAAP financial measures to their most directly comparable GAAP measures. The Partnership’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.
Distributable Cash Flow—The Partnership defines distributable cash flow as net income attributable to Targa Resources Partners LP plus depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for losses (gains) on mark-to-market derivative contracts and debt repurchases, less maintenance capital expenditures (net of any reimbursements of project costs). The impact of noncontrolling interests is included in this measure.
Distributable cash flow is a significant performance metric used by the Partnership and by external users of its financial statements, such as investors, commercial banks and research analysts to compare basic cash flows generated by the Partnership (prior to the establishment of any retained cash reserves by the board of directors of the Partnership’s general partner) to the cash distributions it expects to pay its unitholders. Using this metric, management and external users can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable cash flow is also an important financial measure for the Partnership’s unitholders since it serves as an indicator of the Partnership’s success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not the Partnership is generating cash flow at a level that can sustain or support an increase in its quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the value of a unit of such an entity is generally determined by the unit’s yield (which in turn is based on the amount of cash distributions the entity pays to a unitholder).
The GAAP measure most directly comparable to distributable cash flow is net income attributable to Targa Resources Partners LP. Distributable cash flow should not be considered as an alternative to GAAP net income attributable to Targa Resources Partners LP. Distributable cash flow is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of the Partnership’s results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income attributable to Targa Resources Partners LP and is defined differently by different companies in the Partnership’s industry, the Partnership’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 its decision making processes.
The following table presents a reconciliation of net income attributable to Targa Resources Partners LP to distributable cash flow for the periods indicated:
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| (In millions) | ||||||||||||||||
| Reconciliation of net income attributable to Targa Resources Partners LP to distributable cash flow: |
||||||||||||||||
| Net income attributable to Targa Resources Partners LP |
$ | 46.8 | $ | 55.2 | $ | 117.0 | $ | 93.1 | ||||||||
| Depreciation and amortization expenses |
47.6 | 44.5 | 94.3 | 87.2 | ||||||||||||
| Deferred income tax expense |
0.4 | 1.1 | 0.8 | 1.5 | ||||||||||||
| Amortization in interest expense |
4.4 | 3.8 | 8.9 | 5.7 | ||||||||||||
| Risk management activities |
1.2 | 3.8 | 2.2 | 4.0 | ||||||||||||
| Maintenance capital expenditures |
(15.5 | ) | (21.6 | ) | (31.9 | ) | (32.6 | ) | ||||||||
| Other (1) |
(0.4 | ) | 3.2 | (1.1 | ) | 5.2 | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Distributable cash flow |
$ | 84.5 | $ | 90.0 | $ | 190.2 | $ | 164.1 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| (1) | Includes reimbursements of certain environmental maintenance capital expenditures by TRC and the noncontrolling interest portion of maintenance capital expenditures, depreciation and amortization expense. |
Adjusted EBITDA—The Partnership defines Adjusted EBITDA as net income attributable to Targa Resources Partners LP before interest, income taxes, depreciation and amortization, gains or losses on debt repurchases and non-cash risk management activities related to derivative instruments. Adjusted EBITDA is used as a supplemental financial measure by management and by external users of the Partnership’s financial statements such as investors, commercial banks and others.
The economic substance behind management’s use of Adjusted EBITDA is to measure the ability of the Partnership’s assets to generate cash sufficient to pay interest costs, support indebtedness and make distributions to investors.
The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income attributable to Targa Resources Partners LP. Adjusted EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities or GAAP net income attributable to Targa Resources Partners LP. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors should not consider Adjusted EBITDA in isolation or as a substitute for analysis of the Partnership’s results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income attributable to Targa Resources Partners LP and net cash provided by operating activities and is defined differently by different companies in the Partnership’s industry, the Partnership’s definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.
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 its decision-making processes.
The following table presents a reconciliation of net cash provided by operating activities to Targa Resources Partners LP Adjusted EBITDA for the periods indicated:
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| (In millions) | ||||||||||||||||
| Reconciliation of net cash provided by operating activities to Adjusted EBITDA: |
||||||||||||||||
| Net cash provided by operating activities |
$ | 78.3 | $ | 154.1 | $ | 225.0 | $ | 252.7 | ||||||||
| Net income attributable to noncontrolling interests |
(7.9 | ) | (12.8 | ) | (19.6 | ) | (20.7 | ) | ||||||||
| Interest expense, net (1) |
24.9 | 23.2 | 49.7 | 48.9 | ||||||||||||
| Current income tax expense |
0.4 | 0.8 | 1.0 | 2.2 | ||||||||||||
| Other (2) |
(4.2 | ) | (6.1 | ) | (9.1 | ) | (8.0 | ) | ||||||||
| Changes in operating assets and liabilities which used (provided) cash: |
||||||||||||||||
| Accounts receivable and other assets |
(50.5 | ) | 135.7 | (208.7 | ) | 64.4 | ||||||||||
| Accounts payable and other liabilities |
81.9 | (165.1 | ) | 230.0 | (102.3 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Adjusted EBITDA |
$ | 122.9 | $ | 129.8 | $ | 268.3 | $ | 237.2 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| (1) | Net of amortization of debt issuance costs, discount and premium included in interest expense of $4.4 million and $8.9 million for the three and six months ended June 30, 2012, and $3.8 million and $5.7 million for the three and six months ended June 30, 2011. |
| (2) | Includes equity earnings (loss) from unconsolidated investments – net of distributions, accretion expense associated with asset retirement obligations, amortization of stock based compensation and gain (loss) on sale of assets. |
The following table presents a reconciliation of net income attributable to Targa Resources Partners LP to Adjusted EBITDA for the periods indicated:
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| (In millions) | ||||||||||||||||
| Reconciliation of net income attributable to Targa Resources Partners LP to Adjusted EBITDA: |
||||||||||||||||
| Net income attributable to Targa Resources Partners LP |
$ | 46.8 | $ | 55.2 | $ | 117.0 | $ | 93.1 | ||||||||
| Add: |
||||||||||||||||
| Interest expense, net |
29.4 | 27.2 | 58.8 | 54.6 | ||||||||||||
| Income tax expense |
0.8 | 1.9 | 1.8 | 3.7 | ||||||||||||
| Depreciation and amortization expenses |
47.6 | 44.5 | 94.3 | 87.2 | ||||||||||||
| Risk management activities |
1.2 | 3.8 | 2.2 | 4.0 | ||||||||||||
| Noncontrolling interests adjustment (1) |
(2.9 | ) | (2.8 | ) | (5.8 | ) | (5.4 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Adjusted EBITDA |
$ | 122.9 | $ | 129.8 | $ | 268.3 | $ | 237.2 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| (1) | Noncontrolling interest portion of depreciation and amortization expenses. |
Gross Margin—Gross margin is defined as revenues less purchases. It is impacted by volumes and commodity prices as well as by the Partnership’s contract mix and hedging program. The Partnership defines Natural Gas Gathering and Processing gross margin as total operating revenues from the sales of natural gas and NGLs plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases. Logistics Assets gross margin consists primarily of service fee revenue. Gross margin for Marketing and Distribution equals total revenue from service fees and NGL sales, less cost of sales, which consists primarily of NGL purchases, transportation costs and changes in inventory valuation. The gross margin impact of cash flow settlements from commodity hedging activities is reported in Other.
Operating Margin—Operating margin is an important performance measure of the core profitability of the Partnership’s operations. The Partnership defines operating margin as gross margin less operating expenses. Natural gas and NGL sales revenue includes settlement gains and losses on commodity hedges.
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 substitutes for analysis of the Partnership’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 Partnership’s industry, the Partnership’s definition of gross margin and operating margin may not be comparable to 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.
Management reviews business segment gross margin and operating margin monthly as a core internal management process. The Partnership believes that investors benefit from having access to the same financial measures that its management uses in evaluating our operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures by the Partnership and by external users of the Partnership’s financial statements, including investors and commercial banks to assess:
| • | the financial performance of the Partnership’s assets without regard to financing methods, capital structure or historical cost basis; |
| • | the Partnership’s operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and |
| • | the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. |
Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these insights into its decision-making processes.
The following table presents a reconciliation of gross margin and operating margin to net income for the periods indicated:
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| (In millions) | ||||||||||||||||
| Reconciliation of gross margin and operating margin to net income: |
||||||||||||||||
| Gross margin |
$ | 243.8 | $ | 248.2 | $ | 505.2 | $ | 462.1 | ||||||||
| Operating expenses |
(77.2 | ) | (71.6 | ) | (148.8 | ) | (137.6 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating margin |
166.6 | 176.6 | 356.4 | 324.5 | ||||||||||||
| Depreciation and amortization expenses |
(47.6 | ) | (44.5 | ) | (94.3 | ) | (87.2 | ) | ||||||||
| General and administrative expenses |
(33.5 | ) | (33.2 | ) | (66.4 | ) | (64.9 | ) | ||||||||
| Other operating income (loss) |
— | — | 0.1 | — | ||||||||||||
| Interest expense, net |
(29.4 | ) | (27.2 | ) | (58.8 | ) | (54.6 | ) | ||||||||
| Income tax expense |
(0.8 | ) | (1.9 | ) | (1.8 | ) | (3.7 | ) | ||||||||
| Other, net |
(0.6 | ) | (1.8 | ) | 1.4 | (0.3 | ) | |||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income |
$ | 54.7 | $ | 68.0 | $ | 136.6 | $ | 113.8 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
Targa Resources Corp.—Non-GAAP Financial Measures
This press release includes the Company’s non-GAAP financial measure distributable cash flow. Distributable cash flow should not be considered as an alternative to GAAP measures such as net income or any other GAAP measure of liquidity or financial performance.
Distributable Cash Flow—The Company defines distributable cash flow as net income attributable to Targa Resources Corp. excluding the Partnership’s earnings, plus depreciation and amortization of non-Partnership assets, non-Partnership deferred taxes, distributions that are attributable to the current period of the Partnership, losses (gains) on derivative contracts and certain pre-IPO tax impacts. 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, research analysts and others to compare basic cash flows generated by the Company to the cash dividends the Company expects to pay its shareholders. Using this metric, management can quickly compute the coverage ratio of estimated cash flows to planned 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 also a quantitative standard used throughout the investment community because the share value is generally determined by the share’s yield (which in turn is based on the amount of cash dividends the entity pays to a shareholder).
The economic substance behind the Company’s use of distributable cash flow is to measure the ability of the Company’s assets to generate cash flow sufficient to pay dividends to the Company’s investors.
The GAAP measure most directly comparable to distributable cash flow is net income attributable to Targa Resources Corp. Distributable cash flow should not be considered as an alternative to GAAP net income attributable to Targa Resources Corp. Distributable cash flow is not a presentation made in accordance with GAAP and 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 attributable to Targa Resources Corp. and is defined differently by different companies in the Company’s industry, the Company’s definition of distributable cash flow may not be compatible 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 its decision making process.
The following table presents a reconciliation of net income of Targa Resources Corp. to distributable cash flow for the periods indicated:
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| (In millions) | ||||||||||||||||
| Reconciliation of net income attributable to Targa Resources Corp. to Distributable Cash Flow |
||||||||||||||||
| Net income of Targa Resources Corp. |
$ | 43.5 | $ | 63.3 | $ | 112.6 | $ | 104.1 | ||||||||
| Less: Net income of Targa Resources Partners LP |
(54.7 | ) | (68.0 | ) | (136.6 | ) | (113.8 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net loss for TRC Non-Partnership |
(11.2 | ) | (4.7 | ) | (24.0 | ) | (9.7 | ) | ||||||||
| Plus: TRC Non-Partnership income tax expense |
7.8 | 3.4 | 17.0 | 7.4 | ||||||||||||
| Plus: Distributions from the Partnership |
24.2 | 15.6 | 46.4 | 30.0 | ||||||||||||
| Plus: Non-cash loss (gain) on hedges |
(0.6 | ) | (2.3 | ) | (1.0 | ) | (2.9 | ) | ||||||||
| Plus: Depreciation - Non-Partnership assets |
0.7 | 0.8 | 1.4 | 1.5 | ||||||||||||
| Less: Current cash tax expense (1) |
(5.8 | ) | (2.6 | ) | (12.7 | ) | (5.5 | ) | ||||||||
| Plus: Taxes funded with cash on hand (2) |
2.2 | 2.5 | 4.4 | 5.0 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Distributable cash flow |
$ | 17.3 | $ | 12.7 | $ | 31.5 | $ | 25.8 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| (1) | Excludes $1.2 million and $2.4 million of non-cash current tax expense arising from amortization of deferred long-term tax assets from drop down gains realized for tax purposes and paid in 2010 for the three and six months ended June 30, 2012 and 2011. |
| (2) | Current period portion of amount established at our IPO to fund taxes on deferred gains related to drop down transactions that were treated as sales for income tax purposes. |
The following table presents an alternative reconciliation of cash distributions declared by Targa Resources Partners LP to distributable cash flow of Targa Resources Corp. for the periods indicated:
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| (In millions) | ||||||||||||||||
| Targa Resources Corp. Distributable Cash Flow |
||||||||||||||||
| Distributions declared by Targa Resources Partners LP associated with: |
||||||||||||||||
| General Partner Interests |
$ | 1.5 | $ | 1.2 | $ | 2.9 | $ | 2.3 | ||||||||
| Incentive Distribution Rights |
14.4 | 7.8 | 27.1 | 14.6 | ||||||||||||
| Common Units |
8.3 | 6.6 | 16.4 | 13.1 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total distributions declared by Targa Resources Partners LP Income (expenses) of TRC Non-Partnership |
24.2 | 15.6 | 46.4 | 30.0 | ||||||||||||
| General and administrative expenses |
(2.2 | ) | (1.9 | ) | (4.4 | ) | (4.8 | ) | ||||||||
| Interest expense, net |
(1.1 | ) | (0.8 | ) | (2.2 | ) | (1.9 | ) | ||||||||
| Current cash tax expense (1) |
(5.8 | ) | (2.6 | ) | (12.7 | ) | (5.5 | ) | ||||||||
| Taxes funded with cash on hand (2) |
2.2 | 2.5 | 4.4 | 5.0 | ||||||||||||
| Other income (expense) |
— | (0.1 | ) | — | 3.0 | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Distributable cash flow |
$ | 17.3 | $ | 12.7 | $ | 31.5 | $ | 25.8 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| (1) | Excludes $1.2 million and $2.4 million of non-cash current tax expense arising from amortization of deferred long-term tax assets from drop down gains realized for tax purposes and paid in 2010 for the three and six months ended June 30, 2012 and 2011. |
| (2) | Current period portion of amount established at our IPO to fund taxes on deferred gains related to drop down transactions that were treated as sales for income tax purposes. |
Forward-Looking Statements
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 Partnership and the Company expect, believe or anticipate 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 Partnership’s and the Company’s control, which could cause results to differ materially from those expected by management of the Partnership and 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 and natural gas liquids, 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 Partnership’s and the Company’s filings with the Securities and Exchange Commission, including their Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. Neither the Partnership nor the Company 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.
Matthew Meloy
Senior Vice President, Chief Financial Officer and Treasurer
Joe Brass
Director, Finance
TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED BALANCE SHEETS
(In millions)
| June 30, | December 31, | |||||||
| 2012 | 2011 | |||||||
| ASSETS |
||||||||
| Current assets: |
||||||||
| Cash and cash equivalents |
$ | 89.5 | $ | 55.6 | ||||
| Trade receivables |
368.1 | 575.9 | ||||||
| Inventory |
89.6 | 92.1 | ||||||
| Assets from risk management activities |
56.3 | 41.0 | ||||||
| Other current assets |
2.2 | 2.7 | ||||||
|
|
|
|
|
|||||
| Total current assets |
605.7 | 767.3 | ||||||
|
|
|
|
|
|||||
| Property, plant and equipment, net |
2,952.3 | 2,806.1 | ||||||
| Long-term assets from risk management activities |
21.3 | 10.9 | ||||||
| Other assets |
87.1 | 73.7 | ||||||
|
|
|
|
|
|||||
| Total assets |
$ | 3,666.4 | $ | 3,658.0 | ||||
|
|
|
|
|
|||||
| LIABILITIES AND PARTNERS’ CAPITAL |
||||||||
| Current liabilities: |
||||||||
| Accounts payable and accrued liabilities |
$ | 477.8 | $ | 707.8 | ||||
| Liabilities from risk management activities |
2.8 | 41.1 | ||||||
|
|
|
|
|
|||||
| Total current liabilities |
480.6 | 748.9 | ||||||
|
|
|
|
|
|||||
| Long-term debt payable to third parties |
1,521.0 | 1,477.7 | ||||||
| Long-term liabilities from risk management activities |
4.1 | 15.8 | ||||||
| Other long-term liabilities |
57.1 | 53.9 | ||||||
| Owners’ equity: |
||||||||
| Targa Resources Partners LP owner’s equity |
1,455.3 | 1,222.8 | ||||||
| Noncontrolling interests in subsidiaries |
148.3 | 138.9 | ||||||
|
|
|
|
|
|||||
| Total owners’ equity |
1,603.6 | 1,361.7 | ||||||
|
|
|
|
|
|||||
| Total liabilities and owners’ equity |
$ | 3,666.4 | $ | 3,658.0 | ||||
|
|
|
|
|
|||||
TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit amounts)
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| REVENUES |
$ | 1,318.4 | $ | 1,726.0 | $ | 2,963.9 | $ | 3,341.1 | ||||||||
| Product purchases |
1,074.6 | 1,477.8 | 2,458.7 | 2,879.0 | ||||||||||||
| Operating expenses |
77.2 | 71.6 | 148.8 | 137.6 | ||||||||||||
| Depreciation and amortization expenses |
47.6 | 44.5 | 94.3 | 87.2 | ||||||||||||
| General and administrative expenses |
33.5 | 33.2 | 66.4 | 64.9 | ||||||||||||
| Other operating |
— | — | (0.1 | ) | — | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total costs and expenses |
1,232.9 | 1,627.1 | 2,768.1 | 3,168.7 | ||||||||||||
| INCOME FROM OPERATIONS |
85.5 | 98.9 | 195.8 | 172.4 | ||||||||||||
| Other income (expense): |
||||||||||||||||
| Interest expense, net |
(29.4 | ) | (27.2 | ) | (58.8 | ) | (54.6 | ) | ||||||||
| Equity earnings (loss) |
(0.2 | ) | 1.3 | 1.9 | 3.0 | |||||||||||
| Loss on mark-to-market derivative instruments |
— | (3.2 | ) | — | (3.2 | ) | ||||||||||
| Other income (expense) |
(0.4 | ) | 0.1 | (0.5 | ) | (0.1 | ) | |||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Income before income taxes |
55.5 | 69.9 | 138.4 | 117.5 | ||||||||||||
| Income tax expense |
(0.8 | ) | (1.9 | ) | (1.8 | ) | (3.7 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| NET INCOME |
54.7 | 68.0 | 136.6 | 113.8 | ||||||||||||
| Less: Net income attributable to noncontrolling interests |
7.9 | 12.8 | 19.6 | 20.7 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| NET INCOME ATTRIBUTABLE TO TARGA RESOURCES PARTNERS LP |
$ | 46.8 | $ | 55.2 | $ | 117.0 | $ | 93.1 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income attributable to general partner |
15.4 | 8.9 | 29.5 | 16.5 | ||||||||||||
| Net income allocable to limited partners |
31.4 | 46.3 | 87.5 | 76.6 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income attributable to Targa Resources Partners LP |
$ | 46.8 | $ | 55.2 | $ | 117.0 | $ | 93.1 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income per limited partner unit - basic and diluted |
$ | 0.35 | $ | 0.55 | $ | 0.99 | $ | 0.92 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Basic weighted average limited partner units outstanding |
89.2 | 84.8 | 88.6 | 83.5 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Diluted weighted average limited partner units outstanding |
89.3 | 84.8 | 88.7 | 83.5 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED CASH FLOW INFORMATION
(In millions)
| Six Months Ended June 30, | ||||||||
| 2012 | 2011 | |||||||
| CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||
| Net income |
$ | 136.6 | $ | 113.8 | ||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
| Amortization in interest expense |
9.1 | 5.7 | ||||||
| Compensation on equity grants |
1.6 | 0.8 | ||||||
| Depreciation and other amortization expense |
94.3 | 87.2 | ||||||
| Accretion of asset retirement obligations |
2.0 | 1.8 | ||||||
| Deferred income tax expense |
0.8 | 1.5 | ||||||
| Risk management activities |
2.0 | 4.0 | ||||||
| Gain on sale of assets |
(0.1 | ) | — | |||||
| Changes in operating assets and liabilities |
(21.3 | ) | 37.9 | |||||
|
|
|
|
|
|||||
| Net cash provided by operating activities |
225.0 | 252.7 | ||||||
|
|
|
|
|
|||||
| CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||
| Outlays for property, plant and equipment |
(238.4 | ) | (135.7 | ) | ||||
| Business acquisition |
— | (29.0 | ) | |||||
| Investment in unconsolidated affiliate |
(13.7 | ) | (6.0 | ) | ||||
| Return of capital from unconsolidated affiliate |
0.4 | 0.6 | ||||||
| Other, net |
0.9 | — | ||||||
|
|
|
|
|
|||||
| Net cash used in investing activities |
(250.8 | ) | (170.1 | ) | ||||
|
|
|
|
|
|||||
| CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||
| Proceeds from borrowings under credit facility |
325.0 | 611.0 | ||||||
| Repayments of credit facility |
(683.0 | ) | (1,178.3 | ) | ||||
| Proceeds from issuance of senior notes |
400.0 | 325.0 | ||||||
| Cash paid on note exchange |
— | (27.7 | ) | |||||
| Proceeds from equity offerings |
168.4 | 304.3 | ||||||
| Costs incurred in connection with financing arrangements |
(4.5 | ) | (6.2 | ) | ||||
| Contributions from parent |
0.8 | 5.0 | ||||||
| Distributions to unitholders |
(135.6 | ) | (108.6 | ) | ||||
| Contributions from noncontrolling interest |
4.8 | 1.3 | ||||||
| Distribution to noncontrolling interests |
(16.2 | ) | (11.6 | ) | ||||
|
|
|
|
|
|||||
| Net cash provided by (used in) financing activities |
59.7 | (85.8 | ) | |||||
|
|
|
|
|
|||||
| Net change in cash and cash equivalents |
33.9 | (3.2 | ) | |||||
| Cash and cash equivalents, beginning of period |
55.6 | 76.3 | ||||||
|
|
|
|
|
|||||
| Cash and cash equivalents, end of period |
$ | 89.5 | $ | 73.1 | ||||
|
|
|
|
|
|||||
TARGA RESOURCES CORP.
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per share amounts)
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| REVENUES |
$ | 1,319.1 | $ | 1,728.3 | $ | 2,964.9 | $ | 3,347.0 | ||||||||
| Product purchases |
1,074.6 | 1,477.8 | 2,458.8 | 2,879.0 | ||||||||||||
| Operating expenses |
77.3 | 71.6 | 148.9 | 137.6 | ||||||||||||
| Depreciation and amortization expenses |
48.3 | 45.3 | 95.7 | 88.7 | ||||||||||||
| General and administrative expenses |
35.7 | 35.1 | 70.8 | 69.7 | ||||||||||||
| Other operating |
— | — | (0.1 | ) | — | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total costs and expenses |
1,235.9 | 1,629.8 | 2,774.1 | 3,175.0 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| INCOME FROM OPERATIONS |
83.2 | 98.5 | 190.8 | 172.0 | ||||||||||||
| Other income (expense): |
||||||||||||||||
| Interest expense, net |
(30.5 | ) | (28.0 | ) | (61.0 | ) | (56.5 | ) | ||||||||
| Equity earnings (loss) |
(0.2 | ) | 1.3 | 1.9 | 3.0 | |||||||||||
| Loss on mark-to-market derivative instruments |
— | (3.2 | ) | — | (3.2 | ) | ||||||||||
| Other expenses |
(0.4 | ) | — | (0.3 | ) | (0.1 | ) | |||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Income before income taxes |
52.1 | 68.6 | 131.4 | 115.2 | ||||||||||||
| Income tax expense |
(8.6 | ) | (5.3 | ) | (18.8 | ) | (11.1 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| NET INCOME |
43.5 | 63.3 | 112.6 | 104.1 | ||||||||||||
| Less: Net income attributable to noncontrolling interest |
34.9 | 52.8 | 94.4 | 86.8 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| NET INCOME AVAILABLE TO COMMON SHAREHOLDERS |
$ | 8.6 | $ | 10.5 | $ | 18.2 | $ | 17.3 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income available per common share—basic |
$ | 0.21 | $ | 0.26 | $ | 0.44 | $ | 0.42 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income available per common share—diluted |
$ | 0.21 | $ | 0.25 | $ | 0.44 | $ | 0.42 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Weighted average shares outstanding—basic |
41.0 | 41.0 | 41.0 | 41.0 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Weighted average shares outstanding—diluted |
41.9 | 41.4 | 41.8 | 41.3 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
TARGA RESOURCES CORP.
FINANCIAL SUMMARY (unaudited)
KEY TARGA RESOURCES CORP. BALANCE SHEET ITEMS
(In millions)
| June 30, 2012 | ||||
| Cash and cash equivalents: |
||||
| TRC Non-Partnership |
$ | 28.0 | ||
| Targa Resources Partners |
89.5 | |||
|
|
|
|||
| Total cash and cash equivalents |
$ | 117.5 | ||
|
|
|
|||
| Long-term debt: |
||||
| TRC Non-Partnership |
$ | 89.3 | ||
| Targa Resources Partners |
1,521.0 | |||
|
|
|
|||
| Total long-term debt |
$ | 1,610.3 | ||
|
|
|
|||