UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2015March 31, 2016
or
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from _____ to _____
Commission File Number: 001-33303
TARGA RESOURCES PARTNERS LP
(Exact name of registrant as specified in its charter)
Delaware | 65-1295427 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
1000 Louisiana St, Suite 4300, Houston, Texas | 77002 | |
(Address of principal executive offices) | (Zip Code) |
(713) 584-1000
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑þ No ☐o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ☑ No o☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer | þ | Accelerated filer | o | |
Non-accelerated filer | o | (Do not check if a smaller reporting company) | Smaller reporting company | o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐o No ☑þ.
As of October 30, 2015,May 2, 2016, there were 184,847,901230,002,743 common units representing limited partner interests and 3,772,4064,693,933 general partner units outstanding. As of October 30, 2015,May 2, 2016, there were 5,000,000 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units outstanding.
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4 | ||
5 | ||
6 | ||
7 | ||
8 | ||
9 | ||
35 | ||
52 | ||
57 | ||
PART II—OTHER INFORMATION | ||
58 | ||
58 | ||
58 | ||
58 | ||
58 | ||
59 | ||
60 | ||
SIGNATURES | ||
61 |
Targa Resources Partners LP’s (together with its subsidiaries, “we,” “us,” “our,” “TRP” or “the Partnership”) reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements.” You can typically identify 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, by the use of forward-looking phrases,statements, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.
All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.
These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the following risks and uncertainties:
· |
the timing and extent of changes in natural gas, natural gas liquids (“NGL”), crude oil and other commodity prices, interest rates and demand for our services; |
· |
the level and success of crude oil and natural gas drilling around our assets, our success in connecting natural gas supplies to our gathering and processing systems, oil supplies to our gathering systems and NGL supplies to our logistics and marketing facilities and our success in connecting our facilities to transportation and markets; |
· | our ability to access the capital markets, which will depend on general market conditions and the credit ratings for our debt obligations; |
· | the amount of collateral required to be posted from time to time in our transactions; |
· | our success in risk management activities, including the use of derivative instruments to hedge commodity price risks; |
· | the level of creditworthiness of counterparties to various transactions with us; |
· | changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment; |
· | weather and other natural phenomena; |
· | industry changes, including the impact of consolidations and changes in competition; |
· | our ability to obtain necessary licenses, permits and other approvals; |
· | our ability to grow through acquisitions or internal growth projects and the successful integration and future performance of such assets; including with respect to the Atlas mergers (as defined below); which were completed on February 27, 2015 between Targa Resources Corp. (“Targa,” “Parent” or “TRC”) and Atlas Energy, L.P., a Delaware limited partnership (“ATLS”) and between Atlas Pipeline Partners, L.P., a Delaware limited partnership (“APL”) and us; |
· | general economic, market and business conditions; and |
· | the risks described |
Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report on Form 10-Q for the three months ended March 31, 2016 (the “Quarterly Report”) will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in “Part II –II- Other Information, Item 1A. Risk Factors.” in this Quarterly Report and in our Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.
2
As generally used in the energy industry and in this Quarterly Report, the identified terms have the following meanings:
Bbl | Barrels (equal to 42 U.S. gallons) |
Btu | |
British thermal units, a measure of heating value | |
Bcf | Billion cubic feet |
BBtu | Billion British thermal units |
/d | Per day |
/hr | Per hour |
gal | U.S. gallons |
GPM | Liquid volume equivalent expressed as gallons per 1000 cu. ft. of natural gas |
LPG | Liquefied petroleum gas |
MBbl | Thousand barrels |
MMBbl | Million barrels |
MMBtu | Million British thermal units |
MMcf | Million cubic feet |
NGL(s) | Natural gas liquid(s) |
NYMEX | New York Mercantile Exchange |
LIBOR | London Interbank Offered Rate |
GAAP | Accounting principles generally accepted in the United States of America |
NYSE | |
New York Stock Exchange | |
Price Index Definitions | |
IF-NGPL MC | Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent |
IF-PB | Inside FERC Gas Market Report, Permian Basin |
IF-WAHA | Inside FERC Gas Market Report, West Texas WAHA |
NY-WTI | NYMEX, West Texas Intermediate Crude Oil |
OPIS-MB | Oil Price Information Service, Mont Belvieu, Texas |
NG-NYMEX | NYMEX, Natural Gas |
TARGA RESOURCES PARTNERS LP
|
| March 31, |
|
| December 31, |
| ||||||||||||
|
| 2016 |
|
| 2015 |
| ||||||||||||
|
| (Unaudited) |
| |||||||||||||||
|
| (In millions) |
| |||||||||||||||
ASSETS |
|
|
|
|
|
|
|
| ||||||||||
Current assets: |
|
|
|
|
|
|
|
| ||||||||||
Cash and cash equivalents |
| $ | 103.3 |
|
| $ | 135.4 |
| ||||||||||
Trade receivables, net of allowances of $0.1 million |
|
| 427.6 |
|
|
| 514.8 |
| ||||||||||
Inventories |
|
| 61.7 |
|
|
| 141.0 |
| ||||||||||
Assets from risk management activities |
|
| 82.4 |
|
|
| 92.2 |
| ||||||||||
Other current assets |
|
| 11.8 |
|
|
| 10.0 |
| ||||||||||
Total current assets |
|
| 686.8 |
|
|
| 893.4 |
| ||||||||||
Property, plant and equipment |
|
| 12,107.8 |
|
|
| 11,928.2 |
| ||||||||||
Accumulated depreciation |
|
| (2,373.2 | ) |
|
| (2,225.6 | ) | ||||||||||
Property, plant and equipment, net |
|
| 9,734.6 |
|
|
| 9,702.6 |
| ||||||||||
Intangible assets, net |
|
| 1,765.1 |
|
|
| 1,810.1 |
| ||||||||||
Goodwill, net of impairment provisions |
|
| 393.0 |
|
|
| 417.0 |
| ||||||||||
Long-term assets from risk management activities |
|
| 25.2 |
|
|
| 34.9 |
| ||||||||||
Investments in unconsolidated affiliates |
|
| 254.9 |
|
|
| 258.9 |
| ||||||||||
Other long-term assets |
|
| 9.0 |
|
|
| 9.9 |
| ||||||||||
Total assets |
| $ | 12,868.6 |
|
| $ | 13,126.8 |
| ||||||||||
|
|
|
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|
|
|
| ||||||||||
LIABILITIES AND OWNERS' EQUITY |
|
|
|
|
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|
|
| ||||||||||
Current liabilities: |
|
|
|
|
|
|
|
| ||||||||||
Accounts payable and accrued liabilities |
| $ | 514.8 |
|
| $ | 635.8 |
| ||||||||||
Accounts payable to Targa Resources Corp. |
|
| 24.9 |
|
|
| 30.1 |
| ||||||||||
Liabilities from risk management activities |
|
| 2.0 |
|
|
| 5.2 |
| ||||||||||
Accounts receivable securitization facility |
|
| 150.0 |
|
|
| 219.3 |
| ||||||||||
Total current liabilities |
|
| 691.7 |
|
|
| 890.4 |
| ||||||||||
Long-term debt |
|
| 4,492.9 |
|
|
| 5,125.7 |
| ||||||||||
Long-term liabilities from risk management activities |
|
| 7.9 |
|
|
| 2.4 |
| ||||||||||
Deferred income taxes, net |
|
| 27.0 |
|
|
| 27.2 |
| ||||||||||
Other long-term liabilities |
|
| 149.5 |
|
|
| 178.2 |
| ||||||||||
|
|
|
|
|
|
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| ||||||||||
Contingencies (see Note 15) |
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| ||||||||||
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|
|
|
| ||||||||||
Owners' equity: |
|
|
|
|
|
|
|
| ||||||||||
Series A preferred limited partners | Issued |
|
| Outstanding |
|
|
|
| 120.6 |
|
|
| 120.6 |
| ||||
March 31, 2016 |
| 5,000,000 |
|
|
| 5,000,000 |
|
|
|
|
|
|
|
|
|
| ||
December 31, 2015 |
| 5,000,000 |
|
|
| 5,000,000 |
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common limited partners | Issued |
|
| Outstanding |
|
|
|
| 5,164.8 |
|
|
| 4,550.4 |
| ||||
March 31, 2016 |
| 230,002,743 |
|
|
| 230,002,743 |
|
|
|
|
|
|
|
|
|
| ||
December 31, 2015 | 185,083,420 |
|
| 184,870,693 |
|
|
|
|
|
|
|
|
|
| ||||
General partner |
|
|
|
|
|
|
|
|
|
| 1,717.9 |
|
|
| 1,735.3 |
| ||
March 31, 2016 |
| 4,693,934 |
|
|
| 4,693,934 |
|
|
|
|
|
|
|
|
|
| ||
December 31, 2015 |
| 3,772,871 |
|
|
| 3,772,871 |
|
|
|
|
|
|
|
|
|
| ||
Accumulated other comprehensive income (loss) |
|
|
|
|
| 69.3 |
|
|
| 86.8 |
| |||||||
Treasury units at cost (0 units and 212,727 units as of March 31, 2016 and December 31, 2015) |
|
|
|
| - |
|
|
| (10.3 | ) | ||||||||
|
|
| 7,072.6 |
|
|
| 6,482.8 |
| ||||||||||
Noncontrolling interests in subsidiaries |
|
|
|
|
| 427.0 |
|
|
| 420.1 |
| |||||||
Total owners' equity |
|
| 7,499.6 |
|
|
| 6,902.9 |
| ||||||||||
Total liabilities and owners' equity |
| $ | 12,868.6 |
|
| $ | 13,126.8 |
| ||||||||||
|
|
|
|
|
|
|
|
| ||||||||||
|
|
September 30, 2015 | December 31, 2014 | ||||||||||||||
(Unaudited) (In millions) | |||||||||||||||
ASSETS | |||||||||||||||
Current assets: | |||||||||||||||
Cash and cash equivalents | $ | 92.8 | $ | 72.3 | |||||||||||
Trade receivables, net of allowances of $0.0 million | 620.5 | 566.8 | |||||||||||||
Inventories | 151.1 | 168.9 | |||||||||||||
Assets from risk management activities | 92.3 | 44.4 | |||||||||||||
Other current assets | 8.7 | 3.8 | |||||||||||||
Total current assets | 965.4 | 856.2 | |||||||||||||
Property, plant and equipment | 11,791.6 | 6,514.3 | |||||||||||||
Accumulated depreciation | (2,041.4 | ) | (1,689.7 | ) | |||||||||||
Property, plant and equipment, net | 9,750.2 | 4,824.6 | |||||||||||||
Goodwill | 551.4 | - | |||||||||||||
Intangible assets, net | 1,695.7 | 591.9 | |||||||||||||
Long-term assets from risk management activities | 45.4 | 15.8 | |||||||||||||
Investments in unconsolidated affiliates | 264.2 | 50.2 | |||||||||||||
Other long-term assets | 50.9 | 38.5 | |||||||||||||
Total assets | $ | 13,323.2 | $ | 6,377.2 | |||||||||||
LIABILITIES AND OWNERS' EQUITY | |||||||||||||||
Current liabilities: | |||||||||||||||
Accounts payable and accrued liabilities | $ | 650.5 | $ | 592.7 | |||||||||||
Accounts payable to Targa Resources Corp. | 39.5 | 53.2 | |||||||||||||
Liabilities from risk management activities | 4.3 | 5.2 | |||||||||||||
Accounts receivable securitization facility | 135.5 | 182.8 | |||||||||||||
Total current liabilities | 829.8 | 833.9 | |||||||||||||
Long-term debt | 5,336.4 | 2,783.4 | |||||||||||||
Long-term liabilities from risk management activities | 4.0 | - | |||||||||||||
Deferred income taxes, net | 22.1 | 13.7 | |||||||||||||
Other long-term liabilities | 73.7 | 57.8 | |||||||||||||
Contingencies (see Note 16) | |||||||||||||||
Owners' equity: | |||||||||||||||
Limited partners | Issued | Outstanding | 4,931.5 | 2,384.1 | |||||||||||
September 30, 2015 | 185,049,203 | 184,847,487 | |||||||||||||
December 31, 2014 | 118,652,798 | 118,586,056 | |||||||||||||
General partner | 1,747.5 | 78.6 | |||||||||||||
September 30, 2015 | 3,772,397 | 3,772,397 | |||||||||||||
December 31, 2014 | 2,420,124 | 2,420,124 | |||||||||||||
Receivables from unit issuances | - | (1.0 | ) | ||||||||||||
Accumulated other comprehensive income (loss) | 78.6 | 60.3 | |||||||||||||
Treasury units at cost (201,716 units as of September 30, 2015, and 66,742 as of December 31, 2014) | (10.0 | ) | (4.8 | ) | |||||||||||
6,747.6 | 2,517.2 | ||||||||||||||
Noncontrolling interests in subsidiaries | 309.6 | 171.2 | |||||||||||||
Total owners' equity | 7,057.2 | 2,688.4 | |||||||||||||
Total liabilities and owners' equity | $ | 13,323.2 | $ | 6,377.2 |
See notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF OPERATIONS
|
| Three Months Ended March 31, |
| |||||
|
| 2016 |
|
| 2015 |
| ||
|
| (Unaudited) |
| |||||
|
| (In millions, except per unit amounts) |
| |||||
Revenues: |
|
|
|
|
|
|
|
|
Sales of commodities |
| $ | 1,171.0 |
|
| $ | 1,402.2 |
|
Fees from midstream services |
|
| 271.4 |
|
|
| 277.5 |
|
Total revenues |
|
| 1,442.4 |
|
|
| 1,679.7 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
Product purchases |
|
| 1,011.0 |
|
|
| 1,258.6 |
|
Operating expenses |
|
| 132.0 |
|
|
| 121.1 |
|
Depreciation and amortization expenses |
|
| 193.5 |
|
|
| 118.6 |
|
General and administrative expenses |
|
| 43.4 |
|
|
| 40.2 |
|
Goodwill impairment |
|
| 24.0 |
|
|
| — |
|
Other operating (income) expense |
|
| 1.0 |
|
|
| 0.6 |
|
Income from operations |
|
| 37.5 |
|
|
| 140.6 |
|
Other income (expense): |
|
|
|
|
|
|
|
|
Interest expense, net |
|
| (46.9 | ) |
|
| (50.0 | ) |
Equity earnings (loss) |
|
| (4.8 | ) |
|
| 1.9 |
|
Gain (loss) from financing activities |
|
| 24.7 |
|
|
| — |
|
Other |
|
| (0.1 | ) |
|
| (13.6 | ) |
Income (loss) before income taxes |
|
| 10.4 |
|
|
| 78.9 |
|
Income tax (expense) benefit |
|
| 0.2 |
|
|
| (1.1 | ) |
Net income (loss) |
|
| 10.6 |
|
|
| 77.8 |
|
Less: Net income attributable to noncontrolling interests |
|
| 3.0 |
|
|
| 5.0 |
|
Net income (loss) attributable to Targa Resources Partners LP |
| $ | 7.6 |
|
| $ | 72.8 |
|
|
|
|
|
|
|
|
|
|
Net income attributable to preferred limited partners |
| $ | 2.8 |
|
| $ | — |
|
Net income attributable to general partner |
|
| 14.7 |
|
|
| 42.5 |
|
Net income (loss) attributable to common limited partners |
|
| (9.9 | ) |
|
| 30.3 |
|
Net income (loss) attributable to Targa Resources Partners LP |
| $ | 7.6 |
|
| $ | 72.8 |
|
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
(Unaudited) | ||||||||||||||||
(In millions, except per unit amounts) | ||||||||||||||||
Revenues: | ||||||||||||||||
Sales of commodities | $ | 1,321.3 | $ | 2,009.2 | $ | 4,119.6 | $ | 5,853.3 | ||||||||
Fees from midstream services | 310.8 | 279.1 | 891.6 | 730.4 | ||||||||||||
Total revenues | 1,632.1 | 2,288.3 | 5,011.2 | 6,583.7 | ||||||||||||
Costs and expenses: | ||||||||||||||||
Product purchases | 1,172.4 | 1,880.5 | 3,677.7 | 5,412.2 | ||||||||||||
Operating expenses | 133.6 | 112.8 | 381.8 | 323.6 | ||||||||||||
Depreciation and amortization expenses | 165.8 | 87.5 | 448.3 | 252.8 | ||||||||||||
General and administrative expenses | 42.9 | 40.4 | 130.1 | 115.3 | ||||||||||||
Other operating (income) expense | 0.1 | (4.3 | ) | 0.6 | (5.3 | ) | ||||||||||
Income from operations | 117.3 | 171.4 | 372.7 | 485.1 | ||||||||||||
Other income (expense): | ||||||||||||||||
Interest expense, net | (64.1 | ) | (36.0 | ) | (177.2 | ) | (104.1 | ) | ||||||||
Equity earnings (loss) | (1.6 | ) | 4.7 | (1.1 | ) | 13.8 | ||||||||||
Loss from financing activities (see Note 10) | (0.5 | ) | - | (0.5 | ) | - | ||||||||||
Other | 1.8 | (0.6 | ) | (9.1 | ) | (0.6 | ) | |||||||||
Income before income taxes | 52.9 | 139.5 | 184.8 | 394.2 | ||||||||||||
Income tax (expense) benefit: | ||||||||||||||||
Current | (0.2 | ) | (0.9 | ) | (0.7 | ) | (2.6 | ) | ||||||||
Deferred | 0.6 | (0.4 | ) | 0.3 | (1.1 | ) | ||||||||||
0.4 | (1.3 | ) | (0.4 | ) | (3.7 | ) | ||||||||||
Net income | 53.3 | 138.2 | 184.4 | 390.5 | ||||||||||||
Less: Net income attributable to noncontrolling interests | 4.8 | 9.9 | 17.3 | 30.9 | ||||||||||||
Net income attributable to Targa Resources Partners LP | $ | 48.5 | $ | 128.3 | $ | 167.1 | $ | 359.6 | ||||||||
Net income attributable to general partner | $ | 44.9 | $ | 38.6 | $ | 132.0 | $ | 108.2 | ||||||||
Net income attributable to limited partners | 3.6 | 89.7 | 35.1 | 251.4 | ||||||||||||
Net income attributable to Targa Resources Partners LP | $ | 48.5 | $ | 128.3 | $ | 167.1 | $ | 359.6 | ||||||||
Net income per limited partner unit - basic | $ | 0.02 | $ | 0.78 | $ | 0.21 | $ | 2.21 | ||||||||
Net income per limited partner unit - diluted | $ | 0.02 | $ | 0.78 | $ | 0.21 | $ | 2.20 | ||||||||
Weighted average limited partner units outstanding - basic | 184.8 | 115.1 | 168.1 | 113.9 | ||||||||||||
Weighted average limited partner units outstanding - diluted | 185.1 | 115.7 | 168.5 | 114.5 |
See notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
|
| Three Months Ended March 31, |
| |||||
|
| 2016 |
|
| 2015 |
| ||
|
| (Unaudited) |
| |||||
|
| (In millions) |
| |||||
|
|
|
|
|
|
|
|
|
Net income |
| $ | 10.6 |
|
| $ | 77.8 |
|
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
Commodity hedging contracts: |
|
|
|
|
|
|
|
|
Change in fair value |
|
| 6.7 |
|
|
| 30.3 |
|
Settlements reclassified to revenues |
|
| (24.2 | ) |
|
| (13.2 | ) |
Other comprehensive income (loss) |
|
| (17.5 | ) |
|
| 17.1 |
|
Comprehensive income (loss) |
|
| (6.9 | ) |
|
| 94.9 |
|
Less: Comprehensive income attributable to noncontrolling interests |
|
| 3.0 |
|
|
| 5.0 |
|
Comprehensive income attributable to Targa Resources Partners LP |
| $ | (9.9 | ) |
| $ | 89.9 |
|
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
(Unaudited) | ||||||||||||||||
(In millions) | ||||||||||||||||
Net income | $ | 53.3 | $ | 138.2 | $ | 184.4 | $ | 390.5 | ||||||||
Other comprehensive income (loss): | ||||||||||||||||
Commodity hedging contracts: | ||||||||||||||||
Change in fair value | 42.9 | 14.2 | 59.4 | (4.5 | ) | |||||||||||
Settlements reclassified to revenues | (16.7 | ) | 0.8 | (41.1 | ) | 11.6 | ||||||||||
Interest rate swaps: | ||||||||||||||||
Settlements reclassified to interest expense, net | - | - | - | 2.4 | ||||||||||||
Other comprehensive income (loss) | 26.2 | 15.0 | 18.3 | 9.5 | ||||||||||||
Comprehensive income (loss) | 79.5 | 153.2 | 202.7 | 400.0 | ||||||||||||
Less: Comprehensive income attributable to noncontrolling interests | 4.8 | 9.9 | 17.3 | 30.9 | ||||||||||||
Comprehensive income attributable to Targa Resources Partners LP | $ | 74.7 | $ | 143.3 | $ | 185.4 | $ | 369.1 |
See notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
| Limited |
|
| Limited |
|
| General |
|
| Receivables |
|
| Other |
| Treasury |
|
| Non- |
|
|
|
|
| ||||||||||||||||||||||||
|
| Partner |
|
| Partner |
|
| Partner |
|
| From Unit |
|
| Comprehensive |
|
| Units |
|
| controlling |
|
|
|
|
| |||||||||||||||||||||||
|
| Preferred |
|
| Amount |
|
| Common |
|
| Amount |
|
| Units |
|
| Amount |
|
| Issuances |
|
| Income (Loss) |
|
| Units |
|
| Amount |
|
| Interests |
|
| Total |
| ||||||||||||
|
|
|
|
|
|
|
|
|
| (Unaudited) |
| |||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
| (In millions, except units in thousands) |
| |||||||||||||||||||||||||||||||||||||
Balance December 31, 2015 |
|
| 5,000 |
|
| $ | 120.6 |
|
|
| 184,871 |
|
| $ | 4,550.4 |
|
|
| 3,773 |
|
| $ | 1,735.3 |
|
| $ | — |
|
| $ | 86.8 |
|
|
| 212 |
|
| $ | (10.3 | ) |
| $ | 420.1 |
|
| $ | 6,902.9 |
|
Compensation on equity grants |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2.2 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2.2 |
|
Distribution equivalent rights |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (0.2 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (0.2 | ) |
Issuance of common units under compensation program |
|
| — |
|
|
| — |
|
|
| 30 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Units tendered for tax withholding obligations |
|
| — |
|
|
| — |
|
|
| (1 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| (0.1 | ) |
|
| — |
|
|
| (0.1 | ) |
Cancellation of treasury units |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (10.2 | ) |
|
| — |
|
|
| (0.2 | ) |
|
| — |
|
|
| — |
|
|
| (213 | ) |
|
| 10.4 |
|
|
| — |
|
|
| — |
|
Contributions from Targa Resources Corp. |
|
| — |
|
|
| — |
|
|
| 45,103 |
|
|
| 785.0 |
|
|
| 921 |
|
|
| 16.0 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 801.0 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (2.1 | ) |
|
| (2.1 | ) |
Contributions from noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 6.0 |
|
|
| 6.0 |
|
Other comprehensive income (loss) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (17.5 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (17.5 | ) |
Net income |
|
| — |
|
| 2.8 |
|
|
| — |
|
|
| (9.9 | ) |
|
| — |
|
| 14.7 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 3.0 |
|
|
| 10.6 |
| ||
Distributions |
|
| — |
|
|
| (2.8 | ) |
|
| — |
|
|
| (152.5 | ) |
|
| — |
|
|
| (47.9 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (203.2 | ) |
Balance March 31, 2016 |
|
| 5,000 |
|
| $ | 120.6 |
|
|
| 230,003 |
|
| $ | 5,164.8 |
|
|
| 4,694 |
|
| $ | 1,717.9 |
|
| $ | — |
|
| $ | 69.3 |
|
| $ | — |
|
| $ | — |
|
| $ | 427.0 |
|
| $ | 7,499.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2014 |
|
| — |
|
| $ | — |
|
|
| 118,586 |
|
| $ | 2,384.1 |
|
|
| 2,420 |
|
| $ | 78.6 |
|
| $ | (1.0 | ) |
| $ | 60.3 |
|
|
| 67 |
|
| $ | (4.8 | ) |
| $ | 171.2 |
|
| $ | 2,688.4 |
|
Compensation on equity grants |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 3.8 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 3.8 |
|
Issuance of common units under compensation program |
|
| — |
|
|
| — |
|
|
| 26 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Units tendered for tax withholding obligations |
|
| — |
|
|
| — |
|
|
| (13 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 13 |
|
|
| (0.6 | ) |
|
| — |
|
|
| (0.6 | ) |
Equity offerings |
|
| — |
|
|
| — |
|
|
| 1,271 |
|
|
| 53.0 |
|
|
| — |
|
|
| — |
|
|
| (24.6 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 28.4 |
|
Contributions from Targa Resources Corp. |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,222 |
|
|
| 53.4 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 53.4 |
|
Acquisition of APL |
|
| — |
|
|
| — |
|
|
| 58,614 |
|
|
| 2,583.1 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 113.3 |
|
|
| 2,696.4 |
|
Contributions from noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 3.4 |
|
|
| 3.4 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (2.7 | ) |
|
| (2.7 | ) |
Targa contribution - Special General Partner Interest |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,612.4 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,612.4 |
|
Other comprehensive income (loss) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 17.1 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 17.1 |
|
Net income |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 30.3 |
|
|
| — |
|
|
| 42.5 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 5.0 |
|
|
| 77.8 |
|
Distributions |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (97.0 | ) |
|
| — |
|
|
| (41.1 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (138.1 | ) |
Balance March 31, 2015 |
|
| — |
|
| $ | — |
|
|
| 178,484 |
|
| $ | 4,957.3 |
|
|
| 3,642 |
|
| $ | 1,745.8 |
|
| $ | (25.6 | ) |
| $ | 77.4 |
|
| $ | 80.0 |
|
| $ | (5.4 | ) |
| $ | 290.2 |
|
| $ | 7,039.7 |
|
Limited Partner | General Partner | Receivables From Unit | Accumulated Other | Treasury Units | Non- controlling | |||||||||||||||||||||||||||||||||||
Common | Amount | Units | Amount | Issuances | Income (Loss) | Units | Amount | Interests | Total | |||||||||||||||||||||||||||||||
(Unaudited) | ||||||||||||||||||||||||||||||||||||||||
(In millions, except units in thousands) | ||||||||||||||||||||||||||||||||||||||||
Balance December 31, 2014 | 118,586 | $ | 2,384.1 | 2,420 | $ | 78.6 | $ | (1.0 | ) | $ | 60.3 | 67 | $ | (4.8 | ) | $ | 171.2 | $ | 2,688.4 | |||||||||||||||||||||
Compensation on equity grants | - | 12.8 | - | - | - | - | - | - | - | 12.8 | ||||||||||||||||||||||||||||||
Distribution equivalent rights | - | (1.9 | ) | - | - | - | - | - | - | - | (1.9 | ) | ||||||||||||||||||||||||||||
Issuance of common units under compensation program | 405 | - | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||||||||
Units tendered for tax withholding obligations | (135 | ) | - | - | - | - | - | 135 | (5.2 | ) | - | (5.2 | ) | |||||||||||||||||||||||||||
Equity offerings | 7,377 | 315.4 | - | - | - | - | - | - | - | 315.4 | ||||||||||||||||||||||||||||||
Acquisition of APL | 58,614 | 2,583.1 | - | - | - | - | - | - | 113.4 | 2,696.5 | ||||||||||||||||||||||||||||||
Contributions from Targa Resources Corp. | - | - | 1,352 | 59.1 | 1.0 | - | - | - | - | 60.1 | ||||||||||||||||||||||||||||||
Distributions to noncontrolling interests | - | - | - | - | - | - | - | - | (8.7 | ) | (8.7 | ) | ||||||||||||||||||||||||||||
Contributions from noncontrolling interests | - | - | - | - | - | - | - | - | 16.4 | 16.4 | ||||||||||||||||||||||||||||||
Other comprehensive income (loss) | - | - | - | - | - | 18.3 | - | - | - | 18.3 | ||||||||||||||||||||||||||||||
Net income | - | 35.1 | - | 132.0 | - | - | - | - | 17.3 | 184.4 | ||||||||||||||||||||||||||||||
Distributions | - | (397.1 | ) | - | (134.6 | ) | - | - | - | - | - | (531.7 | ) | |||||||||||||||||||||||||||
Targa contribution - Special General Partner Interest (see Note 2) | - | - | - | 1,612.4 | - | - | - | - | - | 1,612.4 | ||||||||||||||||||||||||||||||
Balance September 30, 2015 | 184,847 | $ | 4,931.5 | 3,772 | $ | 1,747.5 | $ | - | $ | 78.6 | 202 | $ | (10.0 | ) | $ | 309.6 | $ | 7,057.2 | ||||||||||||||||||||||
Balance December 31, 2013 | 111,263 | $ | 2,001.9 | 2,271 | $ | 62.0 | $ | - | $ | (6.1 | ) | - | $ | - | $ | 160.6 | $ | 2,218.4 | ||||||||||||||||||||||
Compensation on equity grants | - | 7.0 | - | - | - | - | - | - | - | 7.0 | ||||||||||||||||||||||||||||||
Distribution equivalent rights | - | (2.0 | ) | - | - | - | - | - | - | - | (2.0 | ) | ||||||||||||||||||||||||||||
Issuance of common units under compensation program | 214 | - | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||||||||
Units tendered for tax withholding obligations | (67 | ) | - | - | - | - | - | 67 | (4.8 | ) | - | (4.8 | ) | |||||||||||||||||||||||||||
Equity offerings | 4,364 | 257.2 | - | - | - | - | - | - | - | 257.2 | ||||||||||||||||||||||||||||||
Contributions from Targa Resources Corp. | - | - | 92 | 5.6 | (0.4 | ) | - | - | - | - | 5.2 | |||||||||||||||||||||||||||||
Distributions to noncontrolling interests | - | - | - | - | - | - | - | - | (26.8 | ) | (26.8 | ) | ||||||||||||||||||||||||||||
Other comprehensive income (loss) | - | - | - | - | - | 9.5 | - | - | - | 9.5 | ||||||||||||||||||||||||||||||
Net income | - | 251.4 | - | 108.2 | - | - | - | - | 30.9 | 390.5 | ||||||||||||||||||||||||||||||
Distributions | - | (260.7 | ) | - | (102.1 | ) | - | - | - | - | - | (362.8 | ) | |||||||||||||||||||||||||||
Balance September 30, 2014 | 115,774 | $ | 2,254.8 | 2,363 | $ | 73.7 | $ | (0.4 | ) | $ | 3.4 | 67 | $ | (4.8 | ) | $ | 164.7 | $ | 2,491.4 |
See notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
| Three Months Ended March 31, |
| |||||
|
| 2016 |
|
| 2015 |
| ||
| (Unaudited) |
| ||||||
| (In millions) |
| ||||||
Cash flows from operating activities |
|
|
|
|
|
|
|
|
Net income (loss) |
| $ | 10.6 |
|
| $ | 77.8 |
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Amortization in interest expense |
|
| 3.4 |
|
|
| 2.9 |
|
Compensation on equity grants |
|
| 2.2 |
|
|
| 3.8 |
|
Depreciation and amortization expense |
|
| 193.5 |
|
|
| 118.6 |
|
Goodwill impairment |
|
| 24.0 |
|
|
| — |
|
Accretion of asset retirement obligations |
|
| 1.1 |
|
|
| 1.3 |
|
Change in redemption value of mandatorily redeemable preferred interest |
|
| (18.5 | ) |
|
| — |
|
Deferred income tax expense (benefit) |
|
| (6.6 | ) |
|
| 0.6 |
|
Equity (earnings) loss of unconsolidated affiliates |
|
| 4.8 |
|
|
| (1.9 | ) |
Distributions received from unconsolidated affiliates |
|
| — |
|
|
| 2.1 |
|
Risk management activities |
|
| 4.4 |
|
|
| 6.5 |
|
(Gain) loss on sale or disposition of assets |
|
| 0.9 |
|
|
| 0.6 |
|
(Gain) loss from financing activities |
|
| (24.7 | ) |
|
| (0.1 | ) |
Changes in operating assets and liabilities, net of business acquisitions: |
|
|
|
|
|
|
|
|
Receivables and other assets |
|
| 99.3 |
|
|
| 78.1 |
|
Inventory |
|
| 62.1 |
|
|
| 102.5 |
|
Accounts payable and other liabilities |
|
| (114.5 | ) |
|
| (102.0 | ) |
Net cash provided by operating activities |
|
| 242.0 |
|
|
| 290.8 |
|
Cash flows from investing activities |
|
|
|
|
|
|
|
|
Outlays for property, plant and equipment |
|
| (190.1 | ) |
|
| (187.6 | ) |
Outlays for business acquisition, net of cash acquired |
|
| — |
|
|
| (828.7 | ) |
Return of capital from unconsolidated affiliates |
|
| 3.4 |
|
|
| 0.6 |
|
Other, net |
|
| (1.3 | ) |
|
| (0.6 | ) |
Net cash used in investing activities |
|
| (188.0 | ) |
|
| (1,016.3 | ) |
Cash flows from financing activities |
|
|
|
|
|
|
|
|
Proceeds from borrowings under credit facility |
|
| 425.0 |
|
|
| 975.0 |
|
Repayments of credit facility |
|
| (705.0 | ) |
|
| (135.0 | ) |
Proceeds from accounts receivable securitization facility |
|
| 5.7 |
|
|
| 253.4 |
|
Repayments of accounts receivable securitization facility |
|
| (75.0 | ) |
|
| (238.3 | ) |
Proceeds from issuance of senior notes |
|
| — |
|
|
| 1,100.0 |
|
Open market purchases of senior notes |
|
| (330.6 | ) |
|
| — |
|
Redemption of APL senior notes |
|
| — |
|
|
| (1,168.8 | ) |
Costs incurred in connection with financing arrangements |
|
| (7.5 | ) |
|
| (12.1 | ) |
Proceeds from sale of common and preferred units |
|
| — |
|
|
| 28.8 |
|
Repurchase of common units under compensation plans |
|
| (0.1 | ) |
|
| (0.6 | ) |
Contributions received from General Partner |
|
| 16.0 |
|
|
| 53.4 |
|
Contributions received from TRC |
|
| 785.0 |
|
|
| — |
|
Contributions received from noncontrolling interests |
|
| 6.0 |
|
|
| 3.4 |
|
Distributions paid to unitholders |
|
| (203.2 | ) |
|
| (138.1 | ) |
Payments of distribution equivalent rights |
|
| (0.3 | ) |
|
| — |
|
Distributions paid to noncontrolling interests |
|
| (2.1 | ) |
|
| (2.7 | ) |
Net cash provided by (used in) financing activities |
|
| (86.1 | ) |
|
| 718.4 |
|
Net change in cash and cash equivalents |
|
| (32.1 | ) |
|
| (7.1 | ) |
Cash and cash equivalents, beginning of period |
|
| 135.4 |
|
|
| 72.3 |
|
Cash and cash equivalents, end of period |
| $ | 103.3 |
|
| $ | 65.2 |
|
Nine Months Ended September 30, | ||||||||
2015 | 2014 | |||||||
(Unaudited) | ||||||||
(In millions) | ||||||||
Cash flows from operating activities | ||||||||
Net income | $ | 184.4 | $ | 390.5 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Amortization in interest expense | 9.3 | 8.8 | ||||||
Compensation on equity grants | 12.8 | 7.0 | ||||||
Depreciation and amortization expense | 448.3 | 252.8 | ||||||
Accretion of asset retirement obligations | 3.9 | 3.3 | ||||||
Deferred income tax expense (benefit) | (0.3 | ) | 1.1 | |||||
Equity (earnings) loss of unconsolidated affiliates | 1.1 | (13.8 | ) | |||||
Distributions received from unconsolidated affiliates | 10.1 | 13.8 | ||||||
Risk management activities | 53.2 | 0.9 | ||||||
(Gain) loss on sale or disposition of assets | (0.2 | ) | (5.6 | ) | ||||
Loss from financing activities | 0.5 | - | ||||||
Changes in operating assets and liabilities, net of business acquisitions: | ||||||||
Receivables and other assets | 126.7 | (40.4 | ) | |||||
Inventory | 31.2 | (115.5 | ) | |||||
Accounts payable and other liabilities | (143.2 | ) | 68.9 | |||||
Net cash provided by operating activities | 737.8 | 571.8 | ||||||
Cash flows from investing activities | ||||||||
Outlays for property, plant and equipment | (625.3 | ) | (571.7 | ) | ||||
Business acquisition, net of cash acquired | (828.7 | ) | - | |||||
Investment in unconsolidated affiliates | (6.6 | ) | - | |||||
Return of capital from unconsolidated affiliates | 1.1 | 4.2 | ||||||
Other, net | (3.0 | ) | 6.3 | |||||
Net cash used in investing activities | (1,462.5 | ) | (561.2 | ) | ||||
Cash flows from financing activities | ||||||||
Proceeds from borrowings under credit facility | 1,646.0 | 1,295.0 | ||||||
Repayments of credit facility | (1,211.0 | ) | (1,115.0 | ) | ||||
Borrowings from accounts receivable securitization facility | 275.5 | 88.9 | ||||||
Repayments of accounts receivable securitization facility | (322.8 | ) | (131.0 | ) | ||||
Proceeds from issuance of senior notes | 1,700.0 | - | ||||||
Redemption of APL senior notes | (1,168.8 | ) | - | |||||
Costs in connection with financing arrangements | (20.7 | ) | (2.7 | ) | ||||
Proceeds from sale of common units | 318.6 | 259.9 | ||||||
Repurchase of common units under compensation plans | (5.2 | ) | (4.8 | ) | ||||
Contributions received from General Partner | 60.1 | 5.2 | ||||||
Contributions received from noncontrolling interests | 16.4 | - | ||||||
Distributions paid to unitholders | �� | (531.7 | ) | (362.8 | ) | |||
Payment of distribution equivalent rights | (2.5 | ) | (1.6 | ) | ||||
Distributions paid to noncontrolling interests | (8.7 | ) | (26.8 | ) | ||||
Net cash provided by financing activities | 745.2 | 4.3 | ||||||
Net change in cash and cash equivalents | 20.5 | 14.9 | ||||||
Cash and cash equivalents, beginning of period | 72.3 | 57.5 | ||||||
Cash and cash equivalents, end of period | $ | 92.8 | $ | 72.4 |
See notes to consolidated financial statements.
(Unaudited)
The year-end condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.
Note 1 — Organization and Operations
Our Organization
Targa Resources Partners LP is a publicly traded Delaware limited partnership formed in October 2006 by Targa. Our common units, which represent limited partner interests in us, are listed onour parent, Targa Resources Corp. (“Targa” or “TRC” or the New York Stock Exchange under the symbol “NGLS.”“Company” or “Parent”). In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries.
On February 17, 2016, TRC completed the previously announced transactions contemplated by the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement”, and such transaction, the “TRC/TRP Merger”), by and among us, Targa Resources GP LLC is(our “general partner”), TRC and Spartan Merger Sub LLC, a Delaware limited liability company formed by Targa in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly owned subsidiary of Targa. AsTRC (“Merger Sub”), pursuant to which TRC acquired indirectly all of September 30, 2015, Targa owned a 10.6% interest in usour outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the formMerger Agreement, Merger Sub merged with and into TRP (the “TRC/TRP Merger”), with TRP continuing as the surviving entity and as a subsidiary of 3,772,397 general partner units and 16,309,594TRC. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units. In addition, Targa Resources GP LLC also owns our incentive distribution rights (“IDRs”), which entitle it to receive increasing cash distributions up to 48%
At the effective time of distributable cash for a quarter, exclusive of amounts reallocated tothe TRC/TRP Merger, each outstanding TRP common unit-holders under the IDR Giveback Amendment (see Note 11-Partnership Units and Related Matters).
Pursuant to the TRC/TRP Merger Agreement, TRC has agreed to cause our issuancecommon units to be delisted from the New York Stock Exchange (“NYSE”) and deregistered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). As a result of the completion of the TRC/TRP Merger, our common units are no longer publicly traded. The 5,000,000 9.0%9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) remain outstanding as limited partner interests in October 2015, our Partnership Agreement was amendedus and restated forcontinue to trade on the purpose of definingNYSE under the preferences, rights, powers and duties of holders of our Preferred Units (see Note 11-Partnership Units and Related Matters).
Our Operations
We are engaged in the business of gathering, compressing, treating, processing and selling natural gas; storing, fractionating, treating, transporting and selling NGLs and NGL products; gathering, storing and terminaling crude oil; and storing, terminaling and selling refined petroleum products. See Note 18-Segment17 – Segment Information for certain financial information for our business segments.
The employees supporting our operations are employed by Targa. Our financial statements include the direct costs of Targa employees deployed to our operating segments, as well as an allocation of costs associated with our usage of Targa’s centralized general and administrative services.
Note 2 — Basis of Presentation
We have prepared these unaudited consolidated financial statements in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. While we derived the year-end balance sheet data from audited financial statements, this interim report does not include all disclosures required by GAAP for annual periods.
These unaudited consolidated financial statements and other information included in this Quarterly Report should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report.TableThe unaudited consolidated financial statements for the three months ended March 31, 2016 and 2015, include all adjustments that we believe are necessary for a fair statement of Contents
9
have been eliminated in consolidation. Certain amounts in prior periods may have been reclassified to conform to the current year presentation.
Our financial results for the three months ended March 31, 2016 are not necessarily indicative of the results that may be expected for the full year.
The February 27, 2015 Atlas mergers involved two separate legal transactions involving different groups of equity holders. For GAAP reporting purposes, these two mergers are viewed as a single integrated transaction. As such, the financial effects of the Targa consideration related to the ATLS merger have been reflected in these financial statements. As described in Note 1,4 – Business Acquisitions, our Partnership Agreement was amended to provide for the issuance of the Special GP Interest in us equal to the tax basis of the APL GP Interests acquired in the ATLS merger totaling $1.6 billion. The Special GP Interest is not entitled to current distributions or allocations of net income or loss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL GP and the right to distributions in liquidation.
Revisions of Previously Reported Activity in our Statement of Changes in Comprehensive Income
During the first quarter of 2016 we concluded that activity related to our commodity hedge contracts was not reported properly in our Statement of Changes in Other Comprehensive Income during 2015. The unaudited consolidated financial statements for the three and nine months ended September 30, 2015 and 2014 include all adjustments that we believe are necessary for a fair presentationerrors resulted in misstatements of the results for interim periods. All significant intercompany balancesstatement caption “Change in fair value” and transactions have been eliminated in consolidation. Certain amounts in prior periods may have beenequal offsetting misstatements of the caption “Settlements reclassified to conformrevenues.” Related income tax effects were also misstated.
We concluded that these misstatements were not material to the current year presentation.
The following table displays the full year.impact of these revisions to activity reported in our Statement of Changes in Other Comprehensive Income during 2015.
|
| Three Months Ended |
| |||||||||||||||||||||
|
| March 31, 2015 |
|
| March 31, 2015 |
|
| June 30, 2015 |
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| June 30, 2015 |
|
| September 30, 2015 |
|
| September 30, 2015 |
| ||||||
|
| As Reported |
|
| As Corrected |
|
| As Reported |
|
| As Corrected |
|
| As Reported |
|
| As Corrected |
| ||||||
Commodity hedging contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value | $ |
| 25.2 |
| $ |
| 30.3 |
| $ |
| (8.7 | ) | $ |
| (3.6 | ) | $ |
| 42.9 |
| $ |
| 50.7 |
|
Settlements reclassified to revenues |
|
| (8.1 | ) |
|
| (13.2 | ) |
|
| (16.3 | ) |
|
| (21.4 | ) |
|
| (16.7 | ) |
|
| (24.5 | ) |
Other comprehensive income (loss) | $ |
| 17.1 |
| $ |
| 17.1 |
| $ |
| (25.0 | ) | $ |
| (25.0 | ) | $ |
| 26.2 |
| $ |
| 26.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
| Six Months Ended |
|
| Nine Months Ended |
|
| Total Year |
| |||||||||||||||
|
| June 30, 2015 |
|
| June 30, 2015 |
|
| September 30, 2015 |
|
| September 30, 2015 |
|
| 2015 |
|
| 2015 |
| ||||||
|
| As Reported |
|
| As Corrected |
|
| As Reported |
|
| As Corrected |
|
| As Reported |
|
| As Corrected |
| ||||||
Commodity hedging contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value | $ |
| 16.5 |
| $ |
| 27.0 |
| $ |
| 59.4 |
| $ |
| 77.6 |
| $ |
| 81.2 |
| $ |
| 112.7 |
|
Settlements reclassified to revenues |
|
| (24.4 | ) |
|
| (34.9 | ) |
|
| (41.1 | ) |
|
| (59.3 | ) |
|
| (54.8 | ) |
|
| (86.3 | ) |
Other comprehensive income (loss) | $ |
| (7.9 | ) | $ |
| (7.9 | ) | $ |
| 18.3 |
| $ |
| 18.3 |
| $ |
| 26.4 |
| $ |
| 26.4 |
|
Note 3 — Significant Accounting Policies
Accounting Policy Updates
The accounting policies that we follow are set forth in Note 33- Significant Accounting Policies of the Notes to Consolidated Financial Statements in our Annual Report. We have updatedReport on Form 10-K. There were no significant updates or revisions to our policies during the ninethree months ended September 30, 2015 to include our accounting policy for goodwill related to the Atlas mergers.
Recent Accounting Pronouncements
In February 2015,May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The update also creates a new Subtopic 340-40, Other Assets and Deferred Costs – Contracts with Customers, which provides guidance for the incremental costs of obtaining a contract with a customer and those costs incurred in fulfilling a contract with a customer that are not in the scope of another topic. The new revenue standard requires that
10
entities should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entities expect to be entitled in exchange for those goods or services. To achieve that core principle, the standard requires a five step process of identifying the contracts with customers, identifying the performance obligations in the contracts, determining the transaction price, allocating the transaction price to the performance obligations, and recognizing revenue when, or as, the performance obligations are satisfied. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.
With the issuance in August 2015 of ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, the revenue recognition standard is effective for the annual period beginning after December 15, 2017, and for annual and interim periods thereafter. Earlier adoption is permitted for annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We must retroactively apply the new revenue recognition standard to transactions in all prior periods presented, but will have a choice between either (1) restating each prior period presented or (2) presenting a cumulative effect adjustment in the period the amendment is adopted. We expect to adopt this guidance on January 1, 2018 and are continuing to evaluate the impact on our revenue recognition practices.
In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The amendments are intended to simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities and modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities. The amendments are effective for us in 2016 with early adoption permitted. We are currently evaluating the effectno impact on our consolidated financial statements or results of the amendments by revisiting our consolidation model for each of our less-than-wholly owned subsidiaries.
In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The amendments in this update require that debt issuance costs related to a recognized debt liability (other than line-of-credit or other revolving credit facilities) be presented in the consolidated balance sheetConsolidated Balance Sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This update dealsdealt solely with financial statement display matters; recognition and measurement of debt issuance costs arewere unaffected. UnamortizedWe adopted the amendments on January 1, 2016 and have reclassified unamortized debt issuance costs of $40.2$38.3 million and $29.9 million for term loans and notes were included inon our Consolidated Balance Sheet as of December 31, 2015 from Other long-term assets on theto Long-term debt to conform to current year presentation. Our Consolidated Balance SheetsSheet as of September 30, 2015 and DecemberMarch 31, 2014. 2016 has $34.0 million in unamortized debt issuance costs classified in Long-term debt.
In August 2015,February 2016, the FASB issued ASU 2015-15,2016-02, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit ArrangementsLeases (Topic 842). The amendment clarifies ASU 2015-03 and provides that an entity may defer and present debt issuance costs for a line-of-credit or other revolving credit facility arrangement as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the arrangement. Unamortized debt issuance costs of $6.5 million and $7.6 million for revolving credit facilities were included in Other long-term assets on the Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014. We will continue to include debt issuance costs for our line-of-credit and revolving credit facility arrangements in Other long-term assets upon adoption of ASU 2015-03. We plan to adopt these standards as of December 31, 2015.
In August 2015,March 2016, the FASB issued ASU 2015-14,2016-08, Revenue from Contracts with Customers (Topic 606): DeferralPrincipal versus Agent Considerations. The amendments in this update improve the operability and understandability of the Effective Date. The amendment defers theimplementation guidance on principal versus agent considerations, including clarifying that an entity should determine whether it is a principal or an agent for each specified good or service promised to a customer. These amendments are effective date of ASU 2014-09, Revenue from Contracts with Customers (Topic 606) by one year. As a result of the amendment, Topic 606 is effective for the annual period beginning December 15, 2017, and for annualfiscal years, and interim periods thereafter,within those years, beginning on or after December 15, 2017, with early adoption permitted. Earlier adoption is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We expect to adopt this guidance on January 1, 2018 and are continuing to evaluate the impact of Topic 606 on our revenue recognition practices.
In September 2015,March 2016, the FASB issued ASU 2015-16, 2016-09,Business Combinations Compensation-Stock Compensation (Topic 805)718): Simplifying theImprovements to Employee Share-Based Payment Accounting for Measurement-Period Adjustments. Topic 805 currently requires that adjustments to provisional amounts recorded in a business combination be recognized retrospectively as if the accounting had been completed at the acquisition date.. The amendments in this update requireprovide, among other things, that an acquirer recognize these measurement-period adjustments(1) all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit in the income statement with the tax effects of exercised or vested awards treated as discrete items in the reporting period in which they occur and recognition of excess tax benefits regardless of whether the adjustment amounts are determined,benefit reduces taxes payable in the current period; (2) excess tax benefits should be classified along with the effect on earnings of changes in depreciation, amortization or other income effects, if any,tax cash flows as an operating activity; (3) an entity can make an entity-wide accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur; (4) the threshold to qualify for equity classification permits withholding up to the maximum statutory tax rates in the applicable jurisdictions; and (5) cash paid by an employer when directly withholding shares for tax-withholding purposes should be classified as a resultfinancing activity on the statement of the changecash flows.
Amendments related to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments require disclosuretiming of the amount recorded in current-period earnings that would have been recorded in previous reporting periods if thewhen excess tax benefits are recognized, minimum statutory withholding requirements, forfeitures, and intrinsic value should be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to the provisional amounts had been recognizedequity as of the acquisition date.beginning of the period in which the guidance is adopted. Amendments related to the presentation of
11
employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirement should be applied retrospectively. Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statement and the practical expedient for estimating expected term should be applied prospectively. An entity may elect to apply the amendments related to the presentation of excess tax benefits on the statement of cash flows using either a prospective transition method or a retrospective transition method. We expect to adopt the amendments in the second quarter of 2016 and are currently evaluating the impacts of the amendments to our financial statements and accounting practices for stock compensation.
In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. These amendments clarify the guidance on identification of performance obligations and licensing. The amendments include that entities do not have to decide if goods and services are effective for usperformance obligations if they are considered immaterial in 2016, with early adoption permitted. We adopted the amendments on September 30, 2015 and have recognized the measurement-period adjustmentscontext of a contract. Entities are also permitted to account for the Atlas mergers determined inshipping and handling that takes place after the three months ended September 30, 2015 in current period earnings. See Note 4 for additional information regarding the nature and amountcustomer has gained control of the measurement-period adjustments.goods as actions to fulfill the contract rather than separate services. In order to identify a performance obligation in a customer contract, an entity has to determine whether the goods or services are distinct, and ASU No. 2016-10 clarifies how the determination can be made.
Note 4 –Business Acquisitions
2015 Acquisition
Atlas Mergers
On February 27, 2015, (i) Targa completed the transactions contemplated by the Agreement and Plan of Merger, dated as of October 13, 2014 (the “ATLS Merger Agreement”), by and among (i) Targa, Targa GP Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of Targa (“GP Merger Sub”), ATLS and Atlas Energy GP, LLC, a Delaware limited liability company and the general partner of ATLS (“ATLS GP”), and (ii) Targa and the Partnership completed the transactions contemplated by the Agreement and Plan of Merger (the “APL Merger Agreement” and, together with the ATLS Merger Agreement, the “Atlas Merger Agreements”) by and among Targa, the Partnership, ourthe Partnership’s general partner, Trident MLP Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of the Partnership (“MLP Merger Sub”), ATLS, APL and Atlas Pipeline Partners GP, LLC, a Delaware limited liability company and the general partner of APL GP.(“APL GP”). Pursuant to the terms and conditions set forth in the ATLS Merger Agreement, GP Merger Sub merged (the “ATLS merger”) with and into ATLS, with ATLS continuing as the surviving entity and as a subsidiary of Targa. Pursuant to the terms and conditions set forth in the APL Merger Agreement, MLP Merger Sub merged (the “APL merger” and, together with the ATLS merger, the “Atlas mergers”) with and into APL, with APL continuing as the surviving entity and as a subsidiary of the Partnership.
In addition, prior to the completion of the Atlas mergers, ATLS, pursuant to a separation and distribution agreement entered into by and among ATLS, ATLS GP and Atlas Energy Group, LLC, a Delaware limited liability company (“AEG”), on February 27, 2015, (i) transferred its assets and liabilities other than those related to its “Atlas Pipeline Partners” segment, to AEG and (ii) effected a pro rata distribution to the ATLS unitholders of AEG common units representing a 100% interest in AEG (collectively, the “Spin-Off” and, together with the Atlas mergers, the “Atlas Transactions”).
On February 27, 2015, the Partnership Agreement was amended to provide for the issuance of a special general partner interest in the Partnership (the “Special GP Interest”) representing the contribution to the Partnership of the APL GP interest acquired in the ATLS merger totaling $1.6 billion. The Special GP Interest is not entitled to current distributions or allocations of net income or loss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL GP and the right to distributions in liquidation.
We acquired all of the outstanding units of APL for a total purchase price of approximately $5.3 billion (including $1.8 billion of acquired debt and all other assumed liabilities). Of the $1.8 billion of debt acquired and other liabilities assumed, approximately $1.2 billion of the acquired debt was tendered and settled upon the closing of the Atlas mergers via our January 2015 cash tender offers. These tender offers were in connection with, and conditioned upon, the consummation of the merger with APL. The merger with APL, however, was not conditioned on the consummation of the tender offers. On that same date, Targa acquired ATLS for a total purchase price of approximately $1.6 billion (including all assumed liabilities).
Pursuant to the APL Merger Agreement, our general partner entered into an amendment to our Partnership Agreement, which we refer to as the IDR Giveback Amendment, in order to reduce aggregate distributions to TRC, as the holder of the Partnership’s IDRs by (a) $9,375,000
12
$9,375,000 per quarter during the first four quarters following the APL merger, (b) $6,250,000 per quarter for the next four quarters, (c) $2,500,000 per quarter for the next four quarters and (d) $1,250,000 per quarter for the next four quarters, with the amount of such reductions to be distributed pro rata to the holders of our outstanding common units.
TPL is a provider of natural gas gathering, processing and treating services primarily in the Anadarko, Arkoma and Permian Basins located in the southwestern and mid-continent regions of the United States and in the Eagle Ford Shale play in south Texas. The Atlas mergers addadded TPL’s Woodford/SCOOP, Mississippi Lime, Eagle Ford and additional Permian assets to the Partnership’s existing operations. In total,
The APL merger was a unit-for-unit transaction with an exchange ratio of 0.5846 of our common units (the “APL Unit Consideration”) and $1.26 in cash for each APL common unit (the “APL Cash Consideration” and, with the APL Unit Consideration, the “APL Merger Consideration”), a $128.0 million total cash payment, of which $0.6 million was expensed at the acquisition date as the cash payment representing accelerated vesting of a portion of retained employees’ APL phantom awards. We issued 58,614,157 of our common units and awarded 629,231 replacement phantom unit awards with a combined value of approximately $2.6 billion as consideration for the APL merger (based on the $43.82 closing market price of a common unit on the NYSE on February 27, 2015). The cash component of the APL merger also included $701.4 million for the mandatory repayment and extinguishment at closing of the APL Senior Secured Revolving Credit Facility that was to mature in May 2017 (the “APL Revolver”), $28.8 million of payments related to change of control and $6.4 million of cash paid in lieu of unit issuances in connection with settlement of APL equity awards for AEG employees. In March 2015, Targa contributed $52.4 million to us to maintain its 2% general partner interest.
In addition, pursuant to the APL Merger Agreement, APL exercised its right under the certificate of designations of the APL 8.25% Class E cumulative redeemable perpetual preferred units (“Class E Preferred Units”) to redeem the APL Class E Preferred Units immediately prior to the effective time of the APL merger.
The ATLS merger was a stock-for-unit transaction with an exchange ratio of 0.1809 of Targa common stock, par value $0.001 per share (the “ATLS Stock Consideration”), and $9.12 in cash for each ATLS common unit (the ATLS Cash Consideration” and, with the ATLS Stock Consideration, the “ATLS Merger Consideration”), (a $514.7 million total cash payment). Targa issued 10,126,532 of its common shares and awarded 81,740 replacement restricted stock units with a combined value of approximately $1.0 billion for the ATLS merger (based on the $99.58 closing market price of a TRC common share on the NYSE on February 27, 2015). The cash component of the ATLS merger also included approximately $149.2 million of payments related to change of control and cash settlements of equity awards, $88.0 million for repayment of a portion of ATLS outstanding indebtedness and $11.0 million for reimbursement of certain transaction expenses. Approximately $4.5 million of the one-time cash payments and cash settlements of equity awards, which represent accelerated vesting of a portion of retained employees’ ATLS phantom units, were expensed at the acquisition date.
ATLS owned, directly and indirectly, 5,754,253 APL common units immediately prior to closing. Targa’s acquisition of ATLS resulted in Targa acquiring these common units (converted to 3,363,935 of our common units) valued at approximately $147.4 million (based on the $43.82 closing market price of our common units on the NYSE on February 27, 2015) and the right to receive the units’ one-time cash payment of approximately $7.3 million, which reduced the consolidated purchase price by approximately $154.7 million.
All outstanding ATLS equity awards, whether vested or unvested, were adjusted in connection with the Spin-Off on the terms and conditions set forth in an Employee Matters Agreement entered into by ATLS, ATLS GP and AEG on February 27, 2015. Following the Spin-Off-related adjustment and at the effective time of the ATLS merger, each outstanding ATLS option and ATLS phantom unit award, whether vested or unvested, held by a person who became an employee of AEG became fully vested (to the extent not vested) and was cancelled and converted into the right to receive the ATLS Merger Consideration in respect of each ATLS common unit underlying the ATLS option or phantom unit award (in the case of options, net of the applicable exercise price). Each outstanding vested ATLS option held by an employee of APL who became an employee of Targa in connection with the Atlas Transactions (a “Midstream Employee”) was cancelled and converted into the right to receive the ATLS Merger Consideration in respect of each ATLS common unit underlying the vested ATLS option, net of the applicable exercise price. Each outstanding unvested ATLS option and each outstanding ATLS phantom unit award held by a Midstream Employee was cancelled and converted into the right to receive (1) the ATLS Cash Consideration in respect of each ATLS common unit underlying such ATLS option or phantom unit award and (2) a TRC restricted stock unit award with respect to a number of shares of TRC Common Stock equal to the product of the ATLS Stock Consideration multiplied by the number of ATLS common units underlying such ATLS option or phantom unit award (in the case of options, net of the applicable exercise price).
In connection with the APL merger, each outstanding APL phantom unit award held by an employee of AEG became fully vested and was cancelled and converted into the right to receive the APL Merger Consideration in respect of each APL common unit underlying the APL phantom unit award. Each outstanding APL phantom unit award held by a Midstream Employee was cancelled and converted
13
into the right to receive (1) the APL Cash Consideration in respect of each APL common unit underlying such APL phantom unit award and (2) a Partnership phantom unit award with respect to a number of our common units equal to the product of the APL Unit Consideration multiplied by the number of APL common units underlying such APL phantom unit award.
The acquired business contributed revenues of $1,065.7$160.6 million and a net lossincome of $1.0$3.4 million to us for the period from February 27, 2015 to September 30,March 31, 2015, and is reported in our Field Gathering and Processing segment.
Pro Forma Impact of Atlas Mergers on Consolidated Statements of Operations
The following summarized unaudited pro forma consolidated statementConsolidated Statement of operationsOperations information for the ninethree months ended September 30, 2015 and September 30, 2014 assumesMarch 31, 2015.assumes that our acquisition of APL and Targa’s acquisition of ATLS had occurred as of January 1, 2014. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma financial results may not be indicative of the results that would have occurred if we had completed these acquisitionsthe APL merger as of January 1, 2014, or that the results that will be attained in the future. Amounts presented below are in millions:
|
| March 31, 2015 |
| |
|
| Pro Forma |
| |
Revenues |
| $ | 1,994.0 |
|
Net income |
|
| 75.2 |
|
Pro Forma Results for the Nine Months Ended | ||||||||
September 30, 2015 | September 30, 2014 | |||||||
Revenues | $ | 5,299.9 | $ | 8,659.5 | ||||
Net income | 178.1 | 462.1 |
The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making adjustments to:
· | Reflect the change in amortization expense resulting from the difference between the historical balances of APL’s intangible assets, net, and |
· | Reflect the change in depreciation expense resulting from the difference between the historical balances of APL’s property, plant and equipment, net, and |
· | Reflect the change in interest expense resulting from our financing activities directly related to the Atlas mergers as compared with APL’s historical interest expense. |
· | Reflect the changes in stock-based compensation expense related to the fair value of the unvested portion of replacement Partnership Long Term Incentive Plan (“LTIP”) awards which were issued in connection with the acquisition to APL phantom unitholders who continue to provide service as Targa employees following the completion of the APL merger. |
· | Remove the results of operations attributable to |
· | Excludes $18.1 million of acquisition-related costs incurred |
· | Reflect the change in APL’s revenues and product purchases to report plant sales of Y-grade at contractual net values |
Fair Value of Consideration Transferred by Targa for ATLS: |
|
|
|
|
Cash paid, net of cash acquired (1) |
| $ | 745.7 |
|
Common shares of TRC |
|
| 1,008.5 |
|
Replacement restricted stock units awarded (3) |
|
| 5.2 |
|
Less: value of APL common units owned by ATLS |
|
| (147.4 | ) |
Total |
| $ | 1,612.0 |
|
|
|
|
|
|
Fair Value of Consideration Transferred by Targa for APL: |
|
|
|
|
Cash paid, net of cash acquired (2) |
| $ | 828.7 |
|
Common units of TRP |
|
| 2,568.5 |
|
Replacement phantom units awarded (3) |
|
| 15.0 |
|
Total |
| $ | 3,412.2 |
|
Total fair value of consideration transferred |
| $ | 5,024.2 |
|
Fair Value of Consideration Transferred by Targa for ATLS: | ||||
Cash paid, net of cash acquired (1) | $ | 745.7 | ||
Common shares of TRC | 1,008.5 | |||
Replacement restricted stock units awarded (3) | 5.2 | |||
Less: value of APL common units owned by ATLS | (147.4 | ) | ||
Total | $ | 1,612.0 | ||
Fair Value of Consideration Transferred by Targa for APL: | ||||
Cash paid, net of cash acquired (2) | $ | 828.7 | ||
Common units of TRP | 2,568.5 | |||
Replacement phantom units awarded (3) | 15.0 | |||
Total | $ | 3,412.2 | ||
Total fair value of consideration transferred | $ | 5,024.2 |
(1) | Targa acquired $5.5 million of cash. |
(2) | We acquired $35.3 million of cash. |
(3) | The fair value of consideration transferred in the form of replacement restricted stock unit awards and replacement phantom unit awards represent the allocation of the fair value of the awards to the pre-combination service period. The fair value of the awards associated with the post-combination service period will be recognized over the remaining service period of the award. |
Our fair value determination related to the Atlas mergers was as follows. The excess of the purchase price over the estimated fair value of net assets acquired was approximately $551.4 million, which was recorded as goodwill. This determination is based on our preliminary valuation and is subject to revisions pending the completion of the valuation and other adjustments.follows:
Fair value determination: |
| February 27, 2015 |
| |
Trade and other current receivables, net |
| $ | 181.1 |
|
Other current assets |
|
| 24.4 |
|
Assets from risk management activities |
|
| 102.1 |
|
Property, plant and equipment |
|
| 4,616.9 |
|
Investments in unconsolidated affiliates |
|
| 214.5 |
|
Intangible assets |
|
| 1,354.9 |
|
Other long-term assets |
|
| 5.5 |
|
Current liabilities |
|
| (258.8 | ) |
Long-term debt |
|
| (1,573.3 | ) |
Deferred income tax liabilities, net |
|
| (13.6 | ) |
Other long-term liabilities |
|
| (119.1 | ) |
Total identifiable net assets |
|
| 4,534.6 |
|
Noncontrolling interest in subsidiaries |
|
| (216.9 | ) |
Current liabilities retained by Targa |
|
| (0.5 | ) |
Goodwill |
|
| 707.0 |
|
Total fair value consideration transferred |
| $ | 5,024.2 |
|
Preliminary fair value determination: | February 27, 2015 | |||
Trade and other current receivables, net | $ | 181.1 | ||
Other current assets | 24.5 | |||
Assets from risk management activities | 102.1 | |||
Property, plant and equipment | 4,703.1 | |||
Investments in unconsolidated affiliates | 219.7 | |||
Intangible assets | 1,199.0 | |||
Other long-term assets | 5.6 | |||
Current liabilities | (257.5 | ) | ||
Long-term debt | (1,573.3 | ) | ||
Deferred income tax liabilities, net | (8.6 | ) | ||
Other long-term liabilities | (9.0 | ) | ||
Total identifiable net assets | 4,586.7 | |||
Noncontrolling interest in subsidiaries | (113.4 | ) | ||
Current liabilities retained by Targa | (0.5 | ) | ||
Goodwill | 551.4 | |||
$ | 5,024.2 |
During the three months ended June 30, 2015, we recorded measurement periodmeasurement-period adjustments to our preliminary acquisition date fair values due to the refinement of our valuation models, assumptions and inputs. As a result, the statementConsolidated Statement of operationsOperations for the three months ended March 31, 2015 was retrospectively adjusted for the impact of measurement-period adjustments to property, plant and equipment, intangible assets, and investmentinvestments in unconsolidated affiliates. These adjustments resulted in a decrease in depreciation and amortization expense of $1.0 million, and an increase in equity earnings of $0.3 million from the amounts previously reported in our Form 10-Q for the quarter ended March 31, 2015.
We adopted the threeamendments to ASU-2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments on September 30, 2015. As a result, during the six months ended September 30,December 31, 2015, we recorded additional quarterly measurement-period adjustments to our preliminary acquisition date fair values due to the refinement of our valuation models, assumptions and inputs. In accordanceinputs, as well as adjustments to previously reported preliminary fair values as a result of our review procedures over the development and application of inputs, assumptions and calculations used in cash-flow based fair value measurements associated with the recent ASU 2015-16, we havebusiness combinations not operating as designed. We recognized these measurement-periodquarterly adjustments in the current reporting period,third and fourth quarters of
15
2015, with the effect on the consolidated statementsConsolidated Statements of operationsOperations resulting from the change to the provisional amounts calculated as if the acquisition had been completed at February 27, 2015. During the three months ended September 30, 2015, the acquisition date fair value of property, plant and equipment increased by $9.9 million, investments in unconsolidated affiliates increased by $5.5 million, intangible assets decreased by $5.0 million, current liabilities increased by $2.4 million, other assets decreased by $1.0 million, and other current assets decreased by $0.6 million, which resulted in a decrease in goodwill of $6.4 million. These adjustments resulted in increased revenues of $0.6 million, a reduction of operating expenses of $1.9 million, depreciation and amortization expense of $0.1 million and equity losses of $0.1 million recorded in the three months ended September 30, 2015, which under the prior accounting standard would have been reflected in previous reporting periods.
The preliminary valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions including projections of future production volumes and cash flows, benchmark analysis of comparable public companies, expectations regarding customer contracts and relationships, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 1413 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation.
The preliminaryexcess of the purchase price over the fair value of net assets acquired was approximately $707.0 million which was recorded as goodwill. The determination of goodwill of $551.4 million is attributable to the workforce of the acquired business and the expected synergies with us and Targa. The goodwill is expected to be amortizable for tax purposes. The attribution of the goodwill to reporting units for the purpose of required future impairment assessments will be completed in conjunction with our finalization of the fair value determination.
The fair value of assets acquired includes trade receivables of $178.1 million. The gross amount due under contracts is $178.1 million, all of which is expected to be collectible. The fair value of assets acquired includes receivables of $3.0 million reported in current receivables and $4.5 million reported in other long-term assets related to a contractual settlement with a counterparty.
Mandatorily Redeemable Preferred Interests
Other long-term liabilities acquired includes $109.3 million related to mandatorily redeemable preferred interests held by our partner in two joint ventures (see Note 10-Debt Obligations for additional disclosures regarding related financing activities associated with the Atlas mergers.
Contingent Consideration
A liability arising from the contingent consideration for APL’s previous acquisition of a gas gathering system and related assets has been recognized at fair value. APL agreed to pay up to an additional $6.0 million if certain volumes are achieved on the acquired gathering system within a specified time period. The fair value of the remaining contingent payment is recorded within other long term liabilities on our Consolidated Balance Sheets. The range of the undiscounted amount that we could pay related to the remaining contingent payment is between $0.0 and $6.0 million. We finalized our acquisition analysis and modeling of this contingent liability during the three months ended June 30, 2015, which resulted in an acquisition date fair value of $4.2 million. Any future change in the fair value of this liability will be included in earnings.
Replacement Phantom Units
In connection with the Atlas mergers, we awarded replacement phantom units in accordance with and as required by the Atlas Merger Agreements to those APL employees who became Targa employees after the acquisition. The vesting dates and terms remained unchanged from the existing APL awards, and will vest over the remaining terms of the awards, which are either 25% per year over the original four year term or 33% per year over the original three year term.
Each replacement phantom unit will entitle the grantee to one common unit on the vesting date and is an equity-settled award. The replacement phantom units include distribution equivalent rights (“DERs”).
When we declare and pay cash distributions, the holders of replacement phantom units will be entitled within 60 days to receive cash payment of DERs in an amount equal to the cash distributions the holders would have received if they were the holders of record on the record date of the number of our common units related to the replacement phantom units.The fair value of the replacement phantom units was based on the closing price of our units at the close of trading on February 27, 2015. The fair value was allocated between the pre-acquisition and post-acquisition periods to determine the amount to be treated as purchase consideration and compensation expense, respectively. Compensation cost will be recognized in general and administrative expense over the remaining service period of each award.
Goodwill
We recognized goodwill at a fair value of approximately $707.0 million associated with the Atlas mergers as of the acquisition date on February 27, 2015. Goodwill has been attributed to the WestTX, SouthTX and SouthOK reporting units in our Gathering and Processing segment. As a result, any level of decrease in the forecasted cash flows from the date of acquisition would likely result in the fair value of the reporting unit to fall below the carrying value of the reporting unit, and could result in an impairment of that reporting unit’s goodwill.
16
As described in Note 3 – Significant Accounting Policies, we evaluate goodwill for impairment at least annually on November 30, or more frequently if we believe necessary based on events or changes in circumstances. As of December 31, 2015, we had not completed our November 30, 2015 impairment assessment. Based on the results of that preliminary evaluation, we recorded a provisional goodwill impairment of $290.0 million during the fourth quarter of 2015. The provisional goodwill impairment reduced the carrying value of goodwill to $417.0 million on our Consolidated Balance Sheets as of December 31, 2015.
During the first quarter of 2016, we finalized our evaluation of goodwill for impairment and have recorded additional impairment expense of $24.0 million in our Consolidated Statement of Operations and reduced the carrying value of goodwill to $393.0 million on our Consolidated Balance Sheets. The impairment of goodwill is primarily due to the effects of lower commodity prices, and a higher cost of capital for companies in our industry compared to conditions in February 2015 when we acquired Atlas. Our evaluation as of November 30, 2015 utilized the income approach (a discounted cash flow analysis (“DCF”)) to estimate the fair values of our reporting units. The future cash flows for our reporting units is based on our estimates, at that time, of future revenues, income from operations and other factors, such as working capital and capital expenditures. We take into account current and expected industry and market conditions, commodity pricing and volumetric forecasts in the basins in which the reporting units operate. The discount rates used in our DCF analysis are based on a weighted average cost of capital determined from relevant market comparisons.
Changes in the gross amounts of our goodwill and impairment loss are as follows:
|
| WestTX |
|
| SouthTX |
|
| SouthOK |
|
| Total |
| ||||
Beginning of period January 1, 2015 |
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
Acquisition February 27, 2015 |
|
| 364.5 |
|
|
| 160.3 |
|
|
| 182.2 |
|
|
| 707.0 |
|
Provisional Impairment |
|
| (37.6 | ) |
|
| (70.2 | ) |
|
| (182.2 | ) |
|
| (290.0 | ) |
Goodwill December 31, 2015 |
|
| 326.9 |
|
|
| 90.1 |
|
|
| — |
|
|
| 417.0 |
|
Additional Impairment |
|
| (14.4 | ) |
|
| (9.6 | ) |
|
| — |
|
|
| (24.0 | ) |
Goodwill March 31, 2016 |
| $ | 312.5 |
|
| $ | 80.5 |
|
| $ | — |
|
| $ | 393.0 |
|
The sustained decrease and uncertain outlook in commodity prices and volumes have adversely impacted our customers and their future capital and operating plans. A continued or prolonged period of lower commodity prices could result in further deterioration of reporting unit fair values and potential further impairment charges related to goodwill and property, plant and equipment.
Note 5 — Inventories
|
| March 31, 2016 |
|
| December 31, 2015 |
| ||
Commodities |
| $ | 49.2 |
|
| $ | 128.3 |
|
Materials and supplies |
|
| 12.5 |
|
|
| 12.7 |
|
|
| $ | 61.7 |
|
| $ | 141.0 |
|
September 30, 2015 | December 31, 2014 | |||||||
Commodities | $ | 138.4 | $ | 157.4 | ||||
Materials and supplies | 12.7 | 11.5 | ||||||
$ | 151.1 | $ | 168.9 |
17
Note 6 — Property, Plant and Equipment and Intangible Assets
Property, Plant and Equipment
|
|
| March 31, 2016 |
|
| December 31, 2015 |
|
| Estimated Useful Lives (In Years) | ||
Gathering systems |
| $ | 6,357.9 |
|
| $ | 6,304.5 |
|
| 5 to 20 | |
Processing and fractionation facilities |
|
| 2,996.5 |
|
|
| 2,988.5 |
|
| 5 to 25 | |
Terminaling and storage facilities |
|
| 1,173.9 |
|
|
| 1,115.0 |
|
| 5 to 25 | |
Transportation assets |
|
| 454.7 |
|
|
| 454.0 |
|
| 10 to 25 | |
Other property, plant and equipment |
|
| 215.2 |
|
|
| 220.9 |
|
| 3 to 25 | |
Land |
|
| 108.8 |
|
|
| 108.8 |
|
| — | |
Construction in progress |
|
| 800.8 |
|
|
| 736.5 |
|
| — | |
Property, plant and equipment |
|
| 12,107.8 |
|
|
| 11,928.2 |
|
|
| |
Accumulated depreciation |
|
| (2,373.2 | ) |
|
| (2,225.6 | ) |
|
| |
Property, plant and equipment, net |
| $ | 9,734.6 |
|
| $ | 9,702.6 |
|
|
| |
|
|
|
|
|
|
|
|
|
|
| |
Intangible assets |
| $ | 2,036.6 |
|
| $ | 2,036.6 |
|
| 20 | |
Accumulated amortization |
|
| (271.5 | ) |
|
| (226.5 | ) |
|
| |
Intangible assets, net |
| $ | 1,765.1 |
|
| $ | 1,810.1 |
|
|
|
September 30, 2015 | December 31, 2014 | Estimated useful life (In Years) | ||||||||||
Gathering systems | $ | 6,187.7 | $ | 2,588.6 | 5 to 20 | |||||||
Processing and fractionation facilities | 2,989.8 | 1,884.1 | 5 to 25 | |||||||||
Terminaling and storage facilities | 1,098.2 | 1,038.9 | 5 to 25 | |||||||||
Transportation assets | 439.5 | 359.0 | 10 to 25 | |||||||||
Other property, plant and equipment | 213.5 | 149.1 | 3 to 25 | |||||||||
Land | 108.5 | 95.6 | - | |||||||||
Construction in progress | 754.4 | 399.0 | - | |||||||||
Property, plant and equipment | 11,791.6 | 6,514.3 | ||||||||||
Accumulated depreciation | (2,041.4 | ) | (1,689.7 | ) | ||||||||
Property, plant and equipment, net | $ | 9,750.2 | $ | 4,824.6 | ||||||||
Intangible assets | $ | 1,880.6 | $ | 681.8 | 20 | |||||||
Accumulated amortization | (184.9 | ) | (89.9 | ) | ||||||||
Intangible assets, net | $ | 1,695.7 | $ | 591.9 |
Intangible assets consist of customer contracts and customer relationships acquired in the Atlas mergers in 2015 and our Badlands business acquisition.acquisition in 2012. The fair values of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. Key valuation assumptions include probability of contracts under negotiation, renewals of existing contracts, economic incentives to retain customers, past and future volumes, current and future capacity of the gathering system, pricing volatility and the discount rate.
The fair values of intangible assets acquired in the Atlas mergers have been recorded at a preliminaryfair value of $1,199.0$1,354.9 million pending completion of final valuations. For the purpose of our preparing the accompanying consolidated financial statements (which includes seven months of amortization of these intangible assets) we haveand are being amortized these intangible assets over a 20 year life using athe straight-line method.
|
| March 31, 2016 |
|
| December 31, 2015 |
| ||
Beginning of period |
| $ | 1,810.1 |
|
| $ | 591.9 |
|
Additions from acquisition |
| — |
|
|
| 1,354.9 |
| |
Amortization |
|
| (45.0 | ) |
|
| (136.7 | ) |
Intangible assets, net |
| $ | 1,765.1 |
|
| $ | 1,810.1 |
|
Note 7 — Asset Retirement Obligations
Nine Months Ended September 30, 2015 | ||||
Beginning of period | $ | 56.8 | ||
Preliminary fair value of ARO acquired with the APL merger | 4.0 | |||
Change in cash flow estimate | 3.8 | |||
Accretion expense | 3.9 | |||
End of period | $ | 68.5 |
Our unconsolidated investments consist of a 38.8% non-operated ownership interest in Gulf Coast Fractionators LP (“GCF”) and
three non-operated joint ventures in South Texas acquired in the AtlasThe following table shows the activity related to our investments in unconsolidated affiliates:
|
| GCF |
|
| T2 LaSalle |
|
| T2 Eagle Ford |
|
| T2 Cogen |
|
| Total |
| |||||
December 31, 2015 |
| $ | 49.5 |
|
| $ | 63.6 |
|
| $ | 123.8 |
|
| $ | 22.0 |
|
| $ | 258.9 |
|
Equity earnings (loss) |
|
| (1.0 | ) |
|
| (1.6 | ) |
|
| (1.3 | ) |
|
| (0.9 | ) |
|
| (4.8 | ) |
Cash distributions (1) |
|
| (3.0 | ) |
|
| — |
|
|
| — |
|
|
| (0.4 | ) |
|
| (3.4 | ) |
Cash calls for expansion projects |
|
| — |
|
|
| — |
|
|
| 4.2 |
|
|
| — |
|
|
| 4.2 |
|
March 31, 2016 |
| $ | 45.5 |
|
| $ | 62.0 |
|
| $ | 126.7 |
|
| $ | 20.7 |
|
| $ | 254.9 |
|
Nine Months Ended September 30, 2015 | ||||||||||||
GCF | T2 Joint Ventures | Total | ||||||||||
Beginning of period | $ | 50.2 | $ | - | $ | 50.2 | ||||||
Preliminary fair value of T2 Joint Ventures acquired | - | 219.7 | 219.7 | |||||||||
Equity earnings (loss) | 10.1 | (11.2 | ) | (1.1 | ) | |||||||
Cash distributions (1) | (10.7 | ) | (0.5 | ) | (11.2 | ) | ||||||
Cash calls for expansion projects | - | 6.6 | 6.6 | |||||||||
End of period | $ | 49.6 | $ | 214.6 | $ | 264.2 |
(1) | Includes |
The recorded value of the T2 Joint Ventures is based on preliminary fair values at the date of acquisition which results in an excess fair value of $45.1$39.9 million over the book value of our partnerthe joint venture capital accounts. This basis difference is attributable to depreciable tangible assets and is being amortized over the preliminary estimated useful lives of the underlying assets of 20 years on a straight-line basis and is included as a component of equity earnings. See Note 4 -– Business Acquisitions for further information regarding the preliminary fair value determinations related to the Atlas mergers.
Note 9 8 — Accounts Payable and Accrued Liabilities
|
| March 31, 2016 |
|
| December 31, 2015 |
| ||
Commodities |
| $ | 322.6 |
|
| $ | 385.3 |
|
Other goods and services |
|
| 92.6 |
|
|
| 141.3 |
|
Interest |
|
| 65.3 |
|
|
| 80.3 |
|
Compensation and benefits |
|
| - |
|
|
| 0.4 |
|
Income and other taxes |
|
| 19.0 |
|
|
| 10.4 |
|
Other |
|
| 15.3 |
|
|
| 18.1 |
|
|
| $ | 514.8 |
|
| $ | 635.8 |
|
September 30, 2015 (1) | December 31, 2014 (1) | |||||||
Commodities | $ | 416.5 | $ | 416.7 | ||||
Other goods and services | 100.5 | 108.9 | ||||||
Interest | 68.0 | 37.3 | ||||||
Compensation and benefits | 1.0 | 1.3 | ||||||
Income and other taxes | 42.6 | 13.6 | ||||||
Other | 21.9 | 14.9 | ||||||
$ | 650.5 | $ | 592.7 |
Accounts payable and accrued liabilities includes $24.1 million and $34.0 million of liabilities to creditors to whom we have issued checks that remain outstanding as of March 31, 2016 and December 31, 2015.
19
|
| March 31, 2016 |
|
| December 31, 2015 |
| ||
Current: |
|
|
|
|
|
|
|
|
Accounts receivable securitization facility, due December 2016 |
| $ | 150.0 |
|
| $ | 219.3 |
|
Long-term: |
|
|
|
|
|
|
|
|
Senior secured revolving credit facility, variable rate, due October 2017 (1) |
|
| - |
|
|
| 280.0 |
|
Senior unsecured notes, 5% fixed rate, due January 2018 |
|
| 935.1 |
|
|
| 1,100.0 |
|
Senior unsecured notes, 4⅛% fixed rate, due November 2019 |
|
| 749.4 |
|
|
| 800.0 |
|
Senior unsecured notes, 6⅝% fixed rate, due October 2020 (2) |
|
| 309.9 |
|
|
| 342.1 |
|
Unamortized premium |
|
| 4.3 |
|
|
| 5.0 |
|
Senior unsecured notes, 6⅞% fixed rate, due February 2021 |
|
| 478.6 |
|
|
| 483.6 |
|
Unamortized discount |
|
| (20.9 | ) |
|
| (22.1 | ) |
Senior unsecured notes, 6⅜% fixed rate, due August 2022 |
|
| 278.7 |
|
|
| 300.0 |
|
Senior unsecured notes, 5¼% fixed rate, due May 2023 |
|
| 559.6 |
|
|
| 583.7 |
|
Senior unsecured notes, 4¼% fixed rate, due November 2023 |
|
| 583.9 |
|
|
| 623.5 |
|
Senior unsecured notes, 6¾% fixed rate, due March 2024 |
|
| 580.1 |
|
|
| 600.0 |
|
Senior unsecured APL notes, 6⅝% fixed rate, due October 2020 (2)(3) |
|
| 12.9 |
|
|
| 12.9 |
|
Unamortized premium |
|
| 0.2 |
|
|
| 0.2 |
|
Senior unsecured APL notes, 4¾% fixed rate, due November 2021 (3) |
|
| 6.5 |
|
|
| 6.5 |
|
Senior unsecured APL notes, 5⅞% fixed rate, due August 2023 (3) |
|
| 48.1 |
|
|
| 48.1 |
|
Unamortized premium |
|
| 0.5 |
|
|
| 0.5 |
|
|
|
| 4,526.9 |
|
|
| 5,164.0 |
|
Debt issuance costs |
|
| (34.0 | ) |
|
| (38.3 | ) |
Total long-term debt |
|
| 4,492.9 |
|
|
| 5,125.7 |
|
Total debt |
| $ | 4,642.9 |
|
| $ | 5,345.0 |
|
Irrevocable standby letters of credit outstanding |
| $ | 12.2 |
|
| $ | 12.9 |
|
September 30, 2015 | December 31, 2014 | |||||||
Current: | ||||||||
Accounts receivable securitization facility, due December 2015 | $ | 135.5 | $ | 182.8 | ||||
Long-term: | ||||||||
Senior secured revolving credit facility, variable rate, due October 2017 (1) | 435.0 | - | ||||||
Senior unsecured notes, 5% fixed rate, due January 2018 | 1,100.0 | - | ||||||
Senior unsecured notes, 4⅛% fixed rate, due November 2019 | 800.0 | 800.0 | ||||||
Senior unsecured notes, 6⅝% fixed rate, due October 2020 (2) | 342.1 | - | ||||||
Unamortized premium | 5.2 | - | ||||||
Senior unsecured notes, 6⅞% fixed rate, due February 2021 | 483.6 | 483.6 | ||||||
Unamortized discount | (23.0 | ) | (25.2 | ) | ||||
Senior unsecured notes, 6⅜% fixed rate, due August 2022 | 300.0 | 300.0 | ||||||
Senior unsecured notes, 5¼% fixed rate, due May 2023 | 600.0 | 600.0 | ||||||
Senior unsecured notes, 4¼% fixed rate, due November 2023 | 625.0 | 625.0 | ||||||
Senior unsecured notes, 6¾% fixed rate, due March 2024 | 600.0 | - | ||||||
Senior unsecured APL notes, 6⅝% fixed rate, due October 2020 (2)(3) | 13.1 | - | ||||||
Unamortized premium | 0.2 | - | ||||||
Senior unsecured APL notes, 4¾% fixed rate, due November 2021 (3) | 6.5 | - | ||||||
Senior unsecured APL notes, 5⅞% fixed rate, due August 2023 (3) | 48.1 | - | ||||||
Unamortized premium | 0.6 | - | ||||||
Total long-term debt | 5,336.4 | 2,783.4 | ||||||
Total debt | $ | 5,471.9 | $ | 2,966.2 | ||||
Irrevocable standby letters of credit outstanding | $ | 11.2 | $ | 44.1 |
(1) | As of |
(2) | In May 2015, we exchanged the TRP 6⅝% Senior Notes with the same economic terms to the holders of the 2020 |
(3) | APL debt is not guaranteed by |
The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the ninethree months ended
|
| Range of Interest Rates Incurred |
|
| Weighted Average Interest Rate Incurred |
| ||
Senior secured revolving credit facility |
| 2.6% - 4.8% |
|
|
| 2.7% |
| |
Accounts receivable securitization facility | �� |
| 1.2% |
|
|
| 1.2% |
|
Range of Interest Rates Incurred | Weighted Average Interest Rate Incurred | |||||||
Senior secured revolving credit facility | 1.9% - 4.3% | 2.2% | ||||||
Accounts receivable securitization facility | 0.9% | 0.9% |
Compliance with Debt Covenants
As of September 30, 2015,March 31, 2016, we were in compliance with the covenants contained in our various debt agreements.
20
During the quarter ended March 31, 2016, we repurchased on the open market a portion of our outstanding Senior Notes as follows:
Debt Issue Repurchased |
| Book Value |
|
| Payment |
|
| Gain/Loss |
|
| Write-off of Debt Issue Costs |
|
| Net Gain (loss) |
| |||||
5¼% Senior Notes |
| $ | 24.1 |
|
| $ | (20.1 | ) |
| $ | 4.0 |
|
| $ | (0.2 | ) |
| $ | 3.8 |
|
4¼% Senior Notes |
|
| 39.5 |
|
|
| (31.8 | ) |
|
| 7.7 |
|
|
| (0.3 | ) |
|
| 7.4 |
|
6⅞% Senior Notes |
|
| 4.8 |
|
|
| (4.3 | ) |
|
| 0.5 |
|
|
| (0.1 | ) |
|
| 0.4 |
|
6⅝% Senior Notes |
|
| 32.6 |
|
|
| (29.5 | ) |
|
| 3.1 |
|
|
| - |
|
|
| 3.1 |
|
6⅜% Senior Notes |
|
| 21.3 |
|
|
| (18.7 | ) |
|
| 2.6 |
|
|
| (0.2 | ) |
|
| 2.4 |
|
6¾% Senior Notes |
|
| 19.9 |
|
|
| (17.5 | ) |
|
| 2.4 |
|
|
| (0.2 | ) |
|
| 2.2 |
|
5% Senior Notes |
|
| 164.9 |
|
|
| (164.5 | ) |
|
| 0.4 |
|
|
| (1.0 | ) |
|
| (0.6 | ) |
4⅛% Senior Notes |
|
| 50.6 |
|
|
| (44.2 | ) |
|
| 6.4 |
|
|
| (0.4 | ) |
|
| 6.0 |
|
|
| $ | 357.7 |
|
| $ | (330.6 | ) |
| $ | 27.1 |
|
| $ | (2.4 | ) |
| $ | 24.7 |
|
We may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Contractual Obligations
The following table summarizes payment obligations for debt instruments after giving effect to 2016 debt repurchases.
|
| Payments Due By Period |
| ||||||||||||||||||||||
|
|
|
|
|
|
| Less Than |
|
|
|
|
|
|
|
|
|
|
|
| More Than |
| ||||
|
| Total |
|
| 1 Year |
|
| 1-3 Years |
|
| 3-5 Years |
|
| 5 Years |
| ||||||||||
Senior Unsecured Debt: |
|
|
| ||||||||||||||||||||||
Debt obligations (1) |
| $ |
| 4,542.8 |
|
| $ |
| - |
|
| $ |
| 935.1 |
|
| $ |
| 1,550.8 |
|
| $ |
| 2,056.9 |
|
Interest on debt obligations (2) |
|
|
| 1,378.1 |
|
|
|
| 191.9 |
|
|
|
| 476.5 |
|
|
|
| 376.5 |
|
|
|
| 333.2 |
|
|
| $ |
| 5,920.9 |
|
| $ |
| 191.9 |
|
| $ |
| 1,411.6 |
|
| $ |
| 1,927.3 |
|
| $ |
| 2,390.1 |
|
(1) | Represents scheduled future maturities of consolidated debt obligations for the periods indicated. |
(2) | Represents interest expense on debt obligations based on both fixed debt interest rates and prevailing March 31, 2016 rates for floating debt. |
Subsequent Events
In February 2015,April 2016, we entered intorepurchased on the First Amendment, Waiver and Incremental Commitment Agreement (the “First Amendment”) that amendedopen market a portion of our Second Amended and Restated Credit Agreement (the “Original Agreement”). The First Amendment increased available commitments to $1.6 billion from $1.2 billion while retaining our ability to request up to an additional $300.0 million in commitment increases. In addition, the First Amendment amends certain provisions of the Original Agreement and designates each of APL and its subsidiaries as an “Unrestricted Subsidiary.” We used proceeds from borrowings under the credit facility to fund some of the cash components of the APL merger, including $701.4 million for the repayments of the APL Revolver and $28.8 million related to change of control payments.
Senior Notes | Outstanding Note Balance | Amount Tendered | Premium Paid | Accrued Interest Paid | Total Tender Offer payments | % Tendered | Note Balance after Tender Offers | |||||||||||||||||||||
($ amounts in millions) | ||||||||||||||||||||||||||||
6⅝% due 2020 | $ | 500.0 | $ | 140.1 | $ | 2.1 | $ | 3.7 | $ | 145.9 | 28.02 | % | $ | 359.9 | ||||||||||||||
4¾% due 2021 | 400.0 | 393.5 | 5.9 | 5.3 | 404.7 | 98.38 | % | 6.5 | ||||||||||||||||||||
5⅞% due 2023 | 650.0 | 601.9 | 8.7 | 2.6 | 613.2 | 92.60 | % | 48.1 | ||||||||||||||||||||
Total | $ | 1,550.0 | $ | 1,135.5 | $ | 16.7 | $ | 11.6 | $ | 1,163.8 | $ | 414.5 |
Note 10 — Other Long-term Liabilities
Other long-term liabilities are comprised of the total outstanding 2020 APL Notes. As a result, the minimum tender conditionfollowing obligations:
|
| March 31, 2016 |
|
| December 31, 2015 |
| ||
Asset retirement obligations |
| $ | 61.9 |
|
| $ | 69.9 |
|
Mandatorily redeemable preferred interests |
|
| 64.1 |
|
|
| 82.9 |
|
Deferred revenue and other |
|
| 23.5 |
|
|
| 25.4 |
|
Total long-term liabilities |
| $ | 149.5 |
|
| $ | 178.2 |
|
21
Our asset retirement obligations (“ARO”) primarily relate to the Exchange Offercertain gas gathering pipelines and related consent solicitation was satisfied,processing facilities, and the APL Issuers entered into a supplemental indenture which eliminated substantially all of the restrictive covenants and certain events of default applicable to the 2020 APL Notes.
|
| March 31, 2016 |
| |
Beginning of period |
| $ | 69.9 |
|
Change in cash flow estimate |
|
| (9.1 | ) |
Accretion expense |
|
| 1.1 |
|
End of period |
| $ | 61.9 |
|
Mandatorily Redeemable Preferred Interests
The following table shows the changes attributable to mandatorily redeemable preferred interests:
|
| March 31, 2016 |
| |
Beginning of period |
| $ | 82.9 |
|
Income (loss) attributable to mandatorily redeemable preferred interests |
|
| (0.3 | ) |
Change in estimated redemption value |
|
| (18.5 | ) |
End of period |
| $ | 64.1 |
|
Note 11 — Partnership Units and Related Matters
TRC/TRP Merger
On February 17, 2016, TRC completed the TRC/TRP Merger with TRP continuing as the surviving entity and a subsidiary of Common Units
At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of TRC shares. No fractional TRC shares were issued 58,614,157in the TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares.
Pursuant to the TRC/TRP Merger Agreement, our common units were delisted from the NYSE and deregistered under the Exchange Act and our common units are no longer publicly traded. The 5,000,000 Preferred Units remain outstanding as limited partner interests in us and continue to former APLtrade on the NYSE. We paid $2.8 million to preferred unitholders as considerationduring the three months ended March 31, 2016. We have accrued distributions to our preferred unitholders of $0.9 million for the APL merger,three months ended March 31, 2016. These distributions were subsequently paid on April 20, 2016.
During the quarter ended March 31, 2016, Targa made capital contributions to us of which 3,363,935$801.0 million. We issued 45,103,140 common units represented ATLS’s common unit ownership in APL and were issued to Targa. Targa contributed $52.4 million to us to maintain its 2%920,472 general partner interest.
22
Targa Resource Partners Long Term Incentive Plan
The TRC/TRP Merger did not trigger the acceleration of January 1, 2015 we had approximately $158.4 millionany time-based vesting of capacity availableany of our outstanding long-term equity incentive compensation awards under our May 2014the Targa Resource Partners Long-Term Incentive Plan. Upon completion of the TRC/TRP Merger, on February 17, 2016, Targa assumed, adopted and amended the Targa Resource Partners Long-Term Incentive Plan (“TRP LTIP”), and has changed the name of the plan to the Targa Resources Corp. Equity Distribution AgreementCompensation Plan (the “May 2014 EDA”“Plan”). In May 2015, we enteredAll outstanding performance unit awards previously granted under the TRP LTIP, were converted and restated into comparable awards based on Targa’s common shares. Specifically, each outstanding performance unit award was converted and restated, effective as of the effective time of the TRC/TRP Merger, into an additional Equity Distribution Agreement under the April 2015 Shelf (the “May 2015 EDA”),award to acquire, pursuant to which we may sell through our sales agents, at our option, upthe same time-based vesting schedule and forfeiture and termination provisions, a comparable number of Targa common shares determined by multiplying the number of performance units subject to an aggregate of $1.0 billioneach award by the exchange ratio in the TRC/TRP Merger (0.62), rounded down to the nearest whole share. The performance factor has been eliminated as it was based on the performance of our common units. During the nine months ended September 30, 2015, we issued 7,377,380 common units versus peer MLPs. All amounts previously credited as distribution equivalent rights under our EDAs, receiving proceeds of $316.1 million (net of commissions). As of September 30, 2015, approximately $4.2 million of capacity and $835.6 million of capacityany outstanding performance unit award continue to remain under the May 2014 and May 2015 EDAs. During the nine months ended September 30, 2015 Targa contributed $6.5 million to us to maintain its 2% general partner interest.
|
|
|
|
|
|
|
|
| Cash-Settled Performance Units |
| |||||||||
|
|
|
|
|
|
|
|
| Targa Resources Long-Term Incentive Plan |
| |||||||||
| Equity-Settled Performance Units |
|
| Replacement Phantom Units |
|
| 2015 |
|
| 2014 |
|
| 2013 |
| |||||
Before Conversion |
| 675,745 |
|
|
| 349,451 |
|
|
| 192,390 |
|
|
| 119,900 |
|
|
| 139,700 |
|
After Conversion |
| 418,903 |
|
|
| 216,561 |
|
|
| 119,178 |
|
|
| 74,248 |
|
|
| 86,538 |
|
The conversion on February 17, 2016 of outstanding equity-settled performance units and replacement phantom units outstanding to equity-settled restricted stock units and replacement phantom shares was considered modification of awards under ASC 718, Accounting for redemption. HoldersStock-Based Compensation (“ASC 718”). The incremental change of Preferred Units have no voting rights except for certain exceptions set forth$3.9 million in our Partnership Agreement.
The conversion on allFebruary 17, 2016 of outstanding Preferred Unitscash-settled performance units outstanding to holderscash-settled restricted stock units was considered modification of recordawards under ASC 718. The incremental change in fair value between the original grant date fair value and the fair value as of February 17, 2016 resulted in recognition of additional compensation costs during the closecurrent quarter of business on October 30, 2015.
Distributions
We must distribute all of our available cash, after distributions to the preferred distribution,Preferred Units, as defined in the Partnership Agreement, and as determined by the general partner, to common unitholders of record within 45 days after the end of each quarter.
|
|
|
| Distributions |
|
|
|
|
| |||||||||||||
|
|
|
| Limited Partners |
|
| General Partner |
|
|
|
|
|
|
|
|
| ||||||
Three Months Ended |
| Date Paid or to be Paid |
| Common |
|
| Incentive |
|
|
| 2% |
|
| Total |
|
| Distributions per Limited Partner Unit |
| ||||
|
|
|
| (In millions, except per unit amounts) |
| |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015 |
| February 9, 2016 |
| $ | 152.5 |
|
| $ | 43.9 |
|
| $ | 4.0 |
|
| $ | 200.4 |
|
| $ | 0.8250 |
|
Distributions | |||||||||||||||||||||||
Three Months Ended | Date Paid or to be Paid | Limited Partners | General Partner | Distributions per Limited Partner Unit | |||||||||||||||||||
Common | Incentive Distribution Rights | 2% | Total | ||||||||||||||||||||
(In millions, except per unit amounts) | |||||||||||||||||||||||
September 30, 2015 | November 13, 2015 | $ | 152.5 | $ | 43.9 | (1) | $ | 4.0 | $ | 200.4 | $ | 0.8250 | |||||||||||
June 30, 2015 | August 14, 2015 | 152.5 | 43.9 | (1) | 4.0 | 200.4 | 0.8250 | ||||||||||||||||
March 31, 2015 | May 15, 2015 | 148.3 | 41.7 | (1) | 3.9 | 193.9 | 0.8200 | ||||||||||||||||
December 31, 2014 | February 13, 2015 | 96.3 | 38.4 | 2.7 | 137.4 | 0.8100 |
On April 19, 2016, our board of directors declared a monthly cash distribution of $0.1875 per preferred Series A Unit for April 2016. This distribution will be paid on May 16, 2016.
Note 12 — Earnings per Limited Partner Unit
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Net income | $ | 53.3 | $ | 138.2 | $ | 184.4 | $ | 390.5 | ||||||||
Less: Net income attributable to noncontrolling interests | 4.8 | 9.9 | 17.3 | 30.9 | ||||||||||||
Net income attributable to Targa Resources Partners LP | $ | 48.5 | $ | 128.3 | $ | 167.1 | $ | 359.6 | ||||||||
Net income attributable to general partner | $ | 44.9 | $ | 38.6 | $ | 132.0 | $ | 108.2 | ||||||||
Net income attributable to limited partners | 3.6 | 89.7 | 35.1 | 251.4 | ||||||||||||
Net income attributable to Targa Resources Partners LP | $ | 48.5 | $ | 128.3 | $ | 167.1 | $ | 359.6 | ||||||||
Weighted average units outstanding - basic | 184.8 | 115.1 | 168.1 | 113.9 | ||||||||||||
Net income available per limited partner unit - basic | $ | 0.02 | $ | 0.78 | $ | 0.21 | $ | 2.21 | ||||||||
Weighted average units outstanding | 184.8 | 115.1 | 168.1 | 113.9 | ||||||||||||
Dilutive effect of unvested stock awards | 0.3 | 0.6 | 0.4 | 0.6 | ||||||||||||
Weighted average units outstanding - diluted (1) | 185.1 | 115.7 | 168.5 | 114.5 | ||||||||||||
Net income available per limited partner unit - diluted | $ | 0.02 | $ | 0.78 | $ | 0.21 | $ | 2.20 |
The primary purpose of our commodity risk management activities is to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have hedged the commodity prices associated with a portion of our expected (i) natural gas equity volumes in our Field Gathering and Processing segment and (ii) NGL and condensate equity volumes predominately in our Field Gathering and Processing segment and the LOU business unit in our Coastal Gathering and Processing segment, that result from percent-of-proceeds processing arrangements. These hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices. We have designated these derivative contracts as cash flow hedges for accounting purposes.
The hedges generally match the NGL product composition and the NGL delivery points of our physical equity volumes. Our natural gas hedges are a mixture of specific gas delivery points and Henry Hub. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations.
We hedge a portion of our condensate equity volumes using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This necessarily exposes us to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes.
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 Partnershipus and included in the acquisition date fair value of assets acquired. Derivative settlements of $20.7 million and $52.2$67.9 million related to these novated contracts were received during the three and nine monthsyear ended September 30,December 31, 2015 and $8.7 million related to these novated contracts were received during the quarter ended March 31, 2016 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.
The "off-market" nature of these acquired derivatives can introduce a degree of ineffectiveness for accounting purposes due to an embedded financing element representing the amount that would be paid or received as of the acquisition date to settle the derivative contract. The resulting ineffectiveness can either potentially disqualify the derivative contract in its entirety for hedge accounting or alternatively affect the amount of unrealized gains or losses on qualifying derivatives that can be deferred from inclusion in periodic net income. Certain novated APL crude options with a fair value of $7.7 million as ofAdditionally, for the acquisition date did not fall within the “highly effective” correlation range required to qualify as a hedging instrument for accounting purposes. These non-qualifying hedges resulted in $1.3quarters ended March 31, 2016 and 2015, we recorded less than $0.1 million and $1.0 million of mark-to-market gains for the three and nine months ended September 30, 2015. These crude oil options expired during 2015. Additionally, for the three and nine months ended September 30, 2015, we recorded $0.4 million and $1.3 million of ineffectiveness gains related to otherwise qualifying APL derivatives, primarily natural gas swaps.
At September 30, 2015,March 31, 2016, the notional volumes of our commodity derivative contracts were:
Commodity | Instrument | Unit | 2016 |
| 2017 |
| 2018 |
| |||
Natural Gas | Swaps | MMBtu/d |
| 91,840 |
|
| 53,982 |
|
| 30,900 |
|
Natural Gas | Basis Swaps | MMBtu/d |
| 43,309 |
|
| 18,082 |
|
| - |
|
Natural Gas | Options | MMBtu/d |
| 22,900 |
|
| 22,900 |
|
| 9,486 |
|
NGL | Swaps | Bbl/d |
| 4,812 |
|
| 1,688 |
|
| 818 |
|
NGL | Futures | Bbl/d |
| 4,331 |
|
| 274 |
|
| - |
|
NGL | Options | Bbl/d |
| 920 |
|
| 920 |
|
| 32 |
|
Condensate | Swaps | Bbl/d |
| 2,375 |
|
| 1,400 |
|
| 900 |
|
Condensate | Options | Bbl/d |
| 790 |
|
| 790 |
|
| 101 |
|
Commodity | Instrument | Unit | 2015 | 2016 | 2017 | 2018 | ||||||
Natural Gas | Swaps | MMBtu/d | 163,456 | 79,399 | 23,082 | - | ||||||
Natural Gas | Basis Swaps | MMBtu/d | 88,099 | 48,962 | 18,082 | - | ||||||
Natural Gas | Collars | MMBtu/d | 15,400 | 22,900 | 22,900 | 9,486 | ||||||
NGL | Swaps | Bbl/d | 4,268 | 2,674 | 1,078 | 208 | ||||||
NGL | Options/Collars | Bbl/d | 920 | 920 | 920 | 32 | ||||||
Condensate | Swaps | Bbl/d | 1,663 | 1,082 | 500 | - | ||||||
Condensate | Options/Collars | Bbl/d | 1,605 | 790 | 790 | 101 |
We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and we record changes in fair value and cash settlements to revenues.
|
|
|
| Fair Value as of March 31, 2016 |
|
| Fair Value as of December 31, 2015 |
| ||||||||||
|
| Balance Sheet |
| Derivative |
|
| Derivative |
|
| Derivative |
|
| Derivative |
| ||||
|
| Location |
| Assets |
|
| Liabilities |
|
| Assets |
|
| Liabilities |
| ||||
Derivatives designated as hedging instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts |
| Current |
| $ | 82.4 |
|
| $ | 1.7 |
|
| $ | 92.1 |
|
| $ | 2.1 |
|
|
| Long-term |
|
| 25.2 |
|
|
| 7.9 |
|
|
| 34.9 |
|
|
| 2.4 |
|
Total derivatives designated as hedging instruments |
|
|
| $ | 107.6 |
|
| $ | 9.6 |
|
| $ | 127.0 |
|
| $ | 4.5 |
|
Derivatives not designated as hedging instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts |
| Current |
| $ | — |
|
| $ | 0.3 |
|
| $ | 0.1 |
|
| $ | 3.1 |
|
Total derivatives not designated as hedging instruments |
|
|
| $ | — |
|
| $ | 0.3 |
|
| $ | 0.1 |
|
| $ | 3.1 |
|
Total current position |
|
|
| $ | 82.4 |
|
| $ | 2.0 |
|
| $ | 92.2 |
|
| $ | 5.2 |
|
Total long-term position |
|
|
|
| 25.2 |
|
|
| 7.9 |
|
|
| 34.9 |
|
|
| 2.4 |
|
Total derivatives |
|
|
| $ | 107.6 |
|
| $ | 9.9 |
|
| $ | 127.1 |
|
| $ | 7.6 |
|
Fair Value as of September 30, 2015 | Fair Value as of December 31, 2014 | ||||||||||||||||
Balance Sheet Location | Derivative Assets | Derivative Liabilities | Derivative Assets | Derivative Liabilities | |||||||||||||
Derivatives designated as hedging instruments | |||||||||||||||||
Commodity contracts | Current | $ | 89.0 | $ | 2.1 | $ | 44.4 | $ | - | ||||||||
Long-term | 45.4 | 4.0 | 15.8 | - | |||||||||||||
Total derivatives designated as hedging instruments | $ | 134.4 | $ | 6.1 | $ | 60.2 | $ | - | |||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||
Commodity contracts | Current | $ | 3.3 | $ | 2.2 | $ | - | $ | 5.2 | ||||||||
Total derivatives not designated as hedging instruments | $ | 3.3 | $ | 2.2 | $ | - | $ | 5.2 | |||||||||
Total current position | $ | 92.3 | $ | 4.3 | $ | 44.4 | $ | 5.2 | |||||||||
Total long-term position | 45.4 | 4.0 | 15.8 | - | |||||||||||||
Total derivatives | $ | 137.7 | $ | 8.3 | $ | 60.2 | $ | 5.2 |
The pro forma impact of reporting derivatives in the Consolidated Balance Sheets on a net basis is as follows:
|
| Gross Presentation |
|
| Pro forma net presentation |
| ||||||||||
March 31, 2016 | Asset |
|
| Liability |
|
| Asset |
|
| Liability |
| |||||
Current Position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| Counterparties with offsetting positions | $ | 79.4 |
|
| $ | 2.0 |
|
| $ | 77.4 |
|
| $ | - |
|
| Counterparties without offsetting positions - assets |
| 3.0 |
|
|
| - |
|
|
| 3.0 |
|
|
| - |
|
| Counterparties without offsetting positions - liabilities |
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
|
| 82.4 |
|
|
| 2.0 |
|
|
| 80.4 |
|
|
| - |
|
Long Term Position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| Counterparties with offsetting positions |
| 25.2 |
|
|
| 7.7 |
|
|
| 17.5 |
|
|
| - |
|
| Counterparties without offsetting positions - assets |
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
| Counterparties without offsetting positions - liabilities |
| - |
|
|
| 0.2 |
|
|
| - |
|
|
| 0.2 |
|
|
|
| 25.2 |
|
|
| 7.9 |
|
|
| 17.5 |
|
|
| 0.2 |
|
Total Derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| Counterparties with offsetting positions |
| 104.6 |
|
|
| 9.7 |
|
|
| 94.9 |
|
|
| - |
|
| Counterparties without offsetting positions - assets |
| 3.0 |
|
|
| - |
|
|
| 3.0 |
|
|
| - |
|
| Counterparties without offsetting positions - liabilities |
| - |
|
|
| 0.2 |
|
|
| - |
|
|
| 0.2 |
|
|
| $ | 107.6 |
|
| $ | 9.9 |
|
| $ | 97.9 |
|
| $ | 0.2 |
|
|
| Gross Presentation |
|
| Pro forma net presentation |
| ||||||||||
December 31, 2015 | Asset |
|
| Liability |
|
| Asset |
|
| Liability |
| |||||
Current Position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| Counterparties with offsetting positions | $ | 86.9 |
|
| $ | 5.2 |
|
| $ | 81.7 |
|
| $ | - |
|
| Counterparties without offsetting positions - assets |
| 5.3 |
|
|
| - |
|
|
| 5.3 |
|
|
| - |
|
| Counterparties without offsetting positions - liabilities |
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
|
| 92.2 |
|
|
| 5.2 |
|
|
| 87.0 |
|
|
| - |
|
Long Term Position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| Counterparties with offsetting positions |
| 34.2 |
|
|
| 2.4 |
|
|
| 31.8 |
|
|
| - |
|
| Counterparties without offsetting positions - assets |
| 0.7 |
|
|
| - |
|
|
| 0.7 |
|
|
| - |
|
| Counterparties without offsetting positions - liabilities |
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
|
| 34.9 |
|
|
| 2.4 |
|
|
| 32.5 |
|
|
| - |
|
Total Derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| Counterparties with offsetting positions |
| 121.1 |
|
|
| 7.6 |
|
|
| 113.5 |
|
|
| - |
|
| Counterparties without offsetting positions - assets |
| 6.0 |
|
|
| - |
|
|
| 6.0 |
|
|
| - |
|
| Counterparties without offsetting positions - liabilities |
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| $ | 127.1 |
|
| $ | 7.6 |
|
| $ | 119.5 |
|
| $ | - |
|
Gross Presentation | Pro Forma Net Presentation | |||||||||||||||
September 30, 2015 | Asset Position | Liability Position | Asset Position | Liability Position | ||||||||||||
Current position | ||||||||||||||||
Counterparties with offsetting position | $ | 87.3 | $ | 4.3 | $ | 83.0 | $ | - | ||||||||
Counterparties without offsetting position - assets | 5.0 | - | 5.0 | - | ||||||||||||
Counterparties without offsetting position - liabilities | - | - | - | - | ||||||||||||
92.3 | 4.3 | 88.0 | - | |||||||||||||
Long-term position | ||||||||||||||||
Counterparties with offsetting position | 44.3 | 4.0 | 40.3 | - | ||||||||||||
Counterparties without offsetting position - assets | 1.1 | - | 1.1 | - | ||||||||||||
Counterparties without offsetting position - liabilities | - | - | - | - | ||||||||||||
45.4 | 4.0 | 41.4 | - | |||||||||||||
Total derivatives | ||||||||||||||||
Counterparties with offsetting position | 131.6 | 8.3 | 123.3 | - | ||||||||||||
Counterparties without offsetting position - assets | 6.1 | - | 6.1 | - | ||||||||||||
Counterparties without offsetting position - liabilities | - | - | - | - | ||||||||||||
$ | 137.7 | $ | 8.3 | $ | 129.4 | $ | - | |||||||||
December 31, 2014 | ||||||||||||||||
Current position | ||||||||||||||||
Counterparties with offsetting position | $ | 35.5 | $ | 4.4 | $ | 31.1 | $ | - | ||||||||
Counterparties without offsetting position - assets | 8.9 | - | 8.9 | - | ||||||||||||
Counterparties without offsetting position - liabilities | - | 0.8 | - | 0.8 | ||||||||||||
44.4 | 5.2 | 40.0 | 0.8 | |||||||||||||
Long-term position | ||||||||||||||||
Counterparties with offsetting position | - | - | - | - | ||||||||||||
Counterparties without offsetting position - assets | 15.8 | - | 15.8 | - | ||||||||||||
Counterparties without offsetting position - liabilities | - | - | - | - | ||||||||||||
15.8 | - | 15.8 | - | |||||||||||||
Total derivatives | ||||||||||||||||
Counterparties with offsetting position | 35.5 | 4.4 | 31.1 | - | ||||||||||||
Counterparties without offsetting position - assets | 24.7 | - | 24.7 | - | ||||||||||||
Counterparties without offsetting position - liabilities | - | 0.8 | - | 0.8 | ||||||||||||
$ | 60.2 | $ | 5.2 | $ | 55.8 | $ | 0.8 |
Our payment obligations in connection with substantially all of these hedging transactions are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders.
25
The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net asset of $129.4$97.7 million as of September 30, 2015.March 31, 2016. The estimated fair value is net of an adjustment for credit risk based on the default probabilities by year as indicated by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented.
The following tables reflect amounts recorded in Other Comprehensive Income (“OCI”) and amounts reclassified from OCI to revenue and expense for the periods indicated:
|
| Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) |
| |||||
Derivatives in Cash Flow |
| Three Months Ended March 31, |
| |||||
Hedging Relationships |
| 2016 |
|
| 2015 |
| ||
Commodity contracts |
| $ | 6.7 |
|
| $ | 30.3 |
|
|
| Gain (Loss) Reclassified from OCI into Income (Effective Portion) |
| |||||
Location of Gain (Loss) |
| Three Months Ended March 31, |
| |||||
|
| 2016 |
|
| 2015 |
| ||
Revenues |
| $ | (24.2 | ) |
| $ | (13.2 | ) |
|
| $ | (24.2 | ) |
| $ | (13.2 | ) |
Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) | ||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
Derivatives in Cash Flow Hedging Relationships | 2015 | 2014 | 2015 | 2014 | ||||||||||||
Commodity contracts | $ | 42.9 | $ | 14.2 | $ | 59.4 | $ | (4.5 | ) |
Gain (Loss) Reclassified from OCI into Income (Effective Portion) | ||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
Location of Gain (Loss) | 2015 | 2014 | 2015 | 2014 | ||||||||||||
Interest expense, net | $ | - | $ | - | $ | - | $ | (2.4 | ) | |||||||
Revenues | 16.7 | (0.8 | ) | 41.1 | (11.6 | ) | ||||||||||
$ | 16.7 | $ | (0.8 | ) | $ | 41.1 | $ | (14.0 | ) |
Our consolidated earnings are also affected by ourthe use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices.
|
| Location of Gain |
| Gain (Loss) Recognized in Income on Derivatives |
| |||||
|
| Recognized in Income on |
| Three Months Ended March 31, |
| |||||
Derivatives Not Designated as Hedging Instruments |
| Derivatives |
| 2016 |
|
| 2015 |
| ||
Commodity contracts |
| Revenue |
| $ | 1.8 |
|
| $ | 7.2 |
|
Gain (Loss) Recognized in Income on Derivatives | ||||||||||||||||||
Derivatives Not Designated as Hedging Instruments | Location of Gain Recognized in Income on Derivatives | Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||||
Commodity contracts | Revenue | $ | (4.0 | ) | $ | (1.5 | ) | $ | (0.9 | ) | $ | (1.4 | ) |
The following table shows the deferred gains (losses) included in accumulated OCI, which will be reclassified into earnings through the end of 2018 based on valuations as of the balance sheet date:
|
| March 31, 2016 |
|
| December 31, 2015 |
| ||
Commodity hedges, before tax (1) |
| $ | 69.3 |
|
| $ | 86.8 |
|
September 30, 2015 | December 31, 2014 | |||||||
Commodity hedges (1) | $ | 78.5 | $ | 60.3 |
(1) | Includes deferred net gains of |
See Note 1413 – Fair Value Measurements for additional disclosures related to derivative instruments and hedging activities.
Note 1413 — Fair Value Measurements
Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“financial instruments”). Derivative financial instruments and contingent consideration related to business acquisitions are reported at fair value in our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost in our Consolidated Balance Sheets. The following are additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments.
Fair Value of Derivative Financial Instruments
Our derivative instruments consist of financially settled commodity swaps, andfutures, option contracts and fixed-price forward commodity contracts with certain counterparties. We determine the fair value of our derivative contracts using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. We have consistently applied these valuation techniques in all periods presented and we believe we have obtained the most accurate information available for the types of derivative contracts we hold.
26
The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. This financial position of these derivatives at September 30, 2015,March 31, 2016, a net asset position of $129.4$97.7 million, reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net asset of $105.3$68.1 million, ignoring an adjustment for counterparty credit risk. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of $152.0$126.0 million, ignoring an adjustment for counterparty credit risk.
Fair Value of Other Financial Instruments
Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. Long-term debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows:
· | The senior secured revolving credit facility (the “TRP Revolver”) and the Securitization Facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and |
· | Senior unsecured notes are based on quoted market prices derived from trades of the debt. |
We have a contingent consideration liability for APL’s previous acquisition of a gas gathering system and related assets, which is carried at fair value (see Note 4 – Business Acquisitions).
Fair Value Hierarchy
We categorize the inputs to the fair value measurements of financial assets and liabilities using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value:
· | Level 1 – observable inputs such as quoted prices in active markets; |
· | Level 2 – inputs other than quoted prices in active markets that we can directly or indirectly observe to the extent that the markets are liquid for the relevant settlement periods; and |
· | Level 3 – unobservable inputs in which little or no market data exists, therefore we must develop our own assumptions. |
|
| March 31, 2016 |
| |||||||||||||||||
|
|
|
|
|
| Fair Value |
| |||||||||||||
|
| Carrying Value |
|
| Total |
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
| |||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets from commodity derivative contracts (1) |
| $ | 104.4 |
|
| $ | 104.4 |
|
| $ | — |
|
| $ | 101.0 |
|
| $ | 3.4 |
|
Liabilities from commodity derivative contracts (1) |
|
| 6.7 |
|
|
| 6.7 |
|
|
| — |
|
|
| 5.9 |
|
|
| 0.8 |
|
TPL contingent consideration (2) |
|
| 3.0 |
|
|
| 3.0 |
|
|
| — |
|
|
| — |
|
|
| 3.0 |
|
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
| 103.3 |
|
|
| 103.3 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Senior unsecured notes |
|
| 4,526.9 |
|
|
| 4,357.1 |
|
|
| — |
|
|
| 4,357.1 |
|
|
| — |
|
Accounts receivable securitization facility |
|
| 150.0 |
|
|
| 150.0 |
|
|
| — |
|
|
| 150.0 |
|
|
| — |
|
|
| December 31, 2015 |
| |||||||||||||||||
|
|
|
|
|
| Fair Value |
| |||||||||||||
|
| Carrying Value |
|
| Total |
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
| |||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets from commodity derivative contracts (1) |
| $ | 127.1 |
|
| $ | 127.1 |
|
| $ | — |
|
| $ | 123.1 |
|
| $ | 4.0 |
|
Liabilities from commodity derivative contracts (1) |
|
| 7.6 |
|
|
| 7.6 |
|
|
| — |
|
|
| 7.3 |
|
|
| 0.3 |
|
TPL contingent consideration (2) |
|
| 3.0 |
|
|
| 3.0 |
|
|
| — |
|
|
| — |
|
|
| 3.0 |
|
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
| 135.4 |
|
|
| 135.4 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Senior secured revolving credit facility |
|
| 280.0 |
|
|
| 280.0 |
|
|
| — |
|
|
| 280.0 |
|
|
| — |
|
Senior unsecured notes |
|
| 4,884.0 |
|
|
| 4,192.0 |
|
|
| — |
|
|
| 4,192.0 |
|
|
| — |
|
Accounts receivable securitization facility |
|
| 219.3 |
|
|
| 219.3 |
|
|
| — |
|
|
| 219.3 |
|
|
| — |
|
September 30, 2015 | ||||||||||||||||||||
Fair Value | ||||||||||||||||||||
Carrying Value | Total | Level 1 | Level 2 | Level 3 | ||||||||||||||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: | ||||||||||||||||||||
Assets from commodity derivative contracts (1) | $ | 137.7 | $ | 137.7 | $ | - | $ | 133.1 | 4.6 | |||||||||||
Liabilities from commodity derivative contracts (1) | 8.3 | 8.3 | - | 7.0 | 1.3 | |||||||||||||||
TPL contingent consideration (2) | 4.2 | 4.2 | - | - | 4.2 | |||||||||||||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: | ||||||||||||||||||||
Cash and cash equivalents | 92.8 | 92.8 | - | - | - | |||||||||||||||
Senior secured revolving credit facility | 435.0 | 435.0 | - | 435.0 | - | |||||||||||||||
Senior unsecured notes | 4,901.4 | 4,567.5 | - | 4,567.5 | - | |||||||||||||||
Accounts receivable securitization facility | 135.5 | 135.5 | - | 135.5 | - |
(1) | The fair value of |
(2) | See Note 4 – Business Acquisitions. |
Additional Information Regarding Level 3 Fair Value Measurements Included in Our Consolidated Balance Sheets
We reported certain of our swaps and option contracts at fair value using Level 3 inputs due to such derivatives not having observable market prices for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods.
The fair value of these natural gas swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For these derivatives, the primary input to the valuation model is the forward commodity basis curve, which is based on observable or public data sources and extrapolated when observable prices are not available.
28
As of September 30, 2015,March 31, 2016, we had 2315 commodity swap and option contracts categorized as Level 3. The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives are the forward natural gas curves, for which a significant portion of the derivative’s term is beyond available forward pricing. The change in the fair value of Level 3 derivatives associated with a 10% change in the forward basis curve where prices are not observable is immaterial.
The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy:
|
|
| Commodity Derivative |
|
|
|
|
| |
|
|
| Contracts |
|
| Contingent |
| ||
|
|
| (Asset)/Liability |
|
| Liability |
| ||
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2015 |
| $ | 3.7 |
|
| $ | 3.0 |
| |
| New Level 3 instruments |
|
| (0.2 | ) |
|
| - |
|
| Settlements included in Revenue |
|
| (0.5 | ) |
|
| - |
|
| Unrealized gain/(loss) included in OCI |
|
| (0.4 | ) |
|
| - |
|
Balance, March 31, 2016 |
| $ | 2.6 |
|
| $ | 3.0 |
|
Commodity Derivative Contracts (Asset)/Liability | Contingent Liability | |||||||
Balance, December 31, 2014 | $ | (1.7 | ) | $ | - | |||
TPL contingent consideration (see Note 4-Business Acquisitions) | - | 4.2 | ||||||
New Level 3 instruments | (3.3 | ) | - | |||||
Transfers out of Level 3 | 1.7 | - | ||||||
Balance, September 30, 2015 | $ | (3.3 | ) | $ | 4.2 |
For the ninethree months ended September 30, 2015, the Partnership transferred $1.7 million inMarch 31, 2016, we had no transfers of derivative liabilities out of Level 3 and into Level 2. These transfersTransfers relate to long-term over-the-counter swaps for natural gas and NGL products with deliveries for which observable market prices were available.
Note 1514 — Related Party Transactions - Targa
Relationship with Targa
We do not have any employees. Targa provides operational, general and administrative and other services to us associated with our existing assets and assets acquired from third parties. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing.
Our Partnership Agreement governs the reimbursement of costs incurred by Targa on behalf of us. Targa charges us for all the direct costs of the employees assigned to our operations, as well as all general and administrative support costs other than (1) costs attributable to Targa’s status as a separate reporting company and (2) costs of Targa providing management and support services to certain unaffiliated spun-off entities. We generally reimburse Targa monthly for cost allocations to the extent that Targa has made a cash outlay.
The following table summarizes transactions with Targa. Management believes these transactions are executed on terms that are fair and reasonable.
|
| Three Months Ended March 31, |
| ||||||
|
| 2016 |
|
|
| 2015 |
| ||
Targa billings of payroll and related costs included in operating expense |
| $ | 40.2 |
|
|
| $ | 34.9 |
|
Targa allocation of general and administrative expense |
|
| 39.9 |
|
|
|
| 38.3 |
|
Cash distributions to Targa based on IDR and unit ownership |
|
| 61.4 |
|
|
|
| 51.6 |
|
Cash contributions from Targa for issuance of common units |
|
| 785.0 |
|
|
|
| — |
|
Cash contributions from Targa to maintain its 2% general partner ownership |
|
| 16.0 |
|
|
|
| 28.8 |
|
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Targa billings of payroll and related costs included in operating expense | $ | 41.4 | $ | 33.1 | $ | 118.3 | $ | 94.6 | ||||||||
Targa allocation of general and administrative expense | 39.4 | 26.4 | 118.3 | 72.4 | ||||||||||||
Cash distributions to Targa based on unit ownership | 61.4 | 46.3 | 172.0 | 131.8 | ||||||||||||
Cash contributions from Targa to maintain its 2% general partner ownership | 1.4 | 1.8 | 60.1 | 5.2 |
Legal Proceedings
Litigation related to TRC/TRP Merger
On December 16, 2015, two purported unitholders of TRP (the “State Court Plaintiffs”) filed a putative class action and derivative lawsuit challenging the TRC/TRP Merger against TRC, TRP (as a nominal defendant), TRP GP, the members of the board of the general partner (the “TRP GP Board”) and Merger Sub (collectively, the “State Court Defendants”). This lawsuit is styled Leslie Blumberg et al. v. TRC Resources Corp., et al., Cause No. 2015-75481, in the District Court of Harris County, Texas, 234th Judicial District (the “State Court Lawsuit”).
The State Court Plaintiffs allege several causes of action challenging the TRC/TRP Merger. Generally, the State Court Plaintiffs allege that (i) the members of the TRP GP Board breached express and/or implied duties under the TRP partnership agreement and (ii) TRC, TRP’s general partner, and Merger Sub aided and abetted in these alleged breaches of duties. The State Court Plaintiffs further allege, in general, that (a) the premium offered to TRP’s unitholders was inadequate, (b) the TRC/TRP Merger did not include a collar to protect TRP unitholders from decreases in TRC’s stock price, (c) the TRP GP Board agreed to contractual terms that allegedly may have dissuaded other potential acquirers from seeking to acquire TRP (including the “no-solicitation,” “matching rights,” and “termination fee” provisions), (d) the process leading up to the TRC/TRP Merger was unfair and (e) the TRP GP Board has conflicts of interest due to TRC’s control of TRP’s general partner.
Based on these allegations, the State Court Plaintiffs sought to enjoin the State Court Defendants from proceeding with or consummating the TRC/TRP Merger unless and until the TRP GP Board adopted and implemented processes to obtain the best possible terms for TRP common unitholders. The State Court Plaintiffs now seek to have the TRC/TRP Merger rescinded and seek attorneys’ fees. On February 26 and 29, 2016, the State Court Defendants filed general denials and asserted affirmative defenses.
The State Court Defendants cannot predict the outcome of this or any other lawsuits that might be filed subsequent to the date of the filing of this report, nor can the State Court Defendants predict the amount of time and expense that will be required to resolve such litigation. The State Court Defendants believe the State Court Lawsuit is without merit and intend to defend vigorously against this lawsuit and any other actions challenging the TRC/TRP Merger.
On January 6 and 19, 2016, two additional purported unitholders of TRP (the “Federal Court Plaintiffs”) filed two putative class action lawsuits challenging the disclosures made in connection with the TRC/TRP Merger against TRP and the members of the TRP GP Board (the “Federal Court Defendants”). These lawsuits have been consolidated as In re Targa Resources Partners, L.P. Securities Litigation, Consolidated C.A. No. 4:16-cv-00041, in the United States District Court for the Southern District of Texas, Houston Division (the “Federal Court Lawsuits”).
The Federal Court Plaintiffs alleged that (i) the Federal Court Defendants have violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder and (ii) the members of the TRP GP Board have violated Section 20(a) of the Exchange Act. The Federal Court Plaintiffs alleged, in general, that the preliminary and definitive joint proxy statements/prospectuses filed in connection with the TRC/TRP Merger failed, among other things, to disclose allegedly material information concerning (i) the TRP GP Conflicts Committee’s financial advisor’s and TRC’s financial advisor’s analyses in connection with the TRC/TRP Merger, (ii) certain TRC and TRP projections, and (iii) the events leading up to the TRC/TRP Merger. The Federal Court Plaintiffs further alleged, in general, that (a) the premium offered to TRP’s unitholders was inadequate, (b) the TRC/TRP Merger did not include a collar to protect TRP unitholders from decreases in TRC’s stock price, (c) the TRP GP Board agreed to contractual terms that allegedly may have dissuaded other potential acquirers from seeking to acquire TRP (including the “no-solicitation,” “matching rights,” and “termination fee” provisions), (d) the process leading up to the TRC/TRP Merger was unfair and (e) the TRP GP Board has conflicts of interest due to TRC’s control of the general partner.
Based on these allegations, the Federal Court Plaintiffs sought to enjoin the Federal Court Defendants from proceeding with or consummating the TRC/TRP Merger unless and until the Federal Court Defendants disclosed the allegedly omitted information summarized above. The Federal Court Plaintiffs also sought damages, attorneys’ fees, and to have the TRC/TRP Merger rescinded.
One of the Federal Court Plaintiffs sought a Temporary Restraining Order (“TRO”) to prevent the Federal Court Defendants from proceeding with the TRC/TRP vote and/or merger. On January 29, 2016, this Plaintiff was denied his request for a TRO. On April 20, 2016, the court dismissed the Federal Court Lawsuits without prejudice.
30
Between October and December 2014, five public unitholders of APL (the “APL Plaintiffs”) filed putative class action lawsuits against APL, ATLS, APL GP, its managers, Targa, the Partnership, the general partner and MLP MergerMerger Sub (the “APL Lawsuit Defendants”). These lawsuits arewere styled (a) Michael Evnin v. Atlas Pipeline Partners, L.P., et al., ., in the Court of Common Pleas for Allegheny County, Pennsylvania; (b) William B. Federman Family Wealth Preservation Trust v. Atlas Pipeline Partners, L.P., et al.,in the District Court of Tulsa County, Oklahoma (the “Tulsa Lawsuit”); (c) Greenthal Living Trust U/A 01/26/88 v. Atlas Pipeline Partners, L.P., et al., ., in the Court of Common Pleas for Allegheny County, Pennsylvania; (d) Mike Welborn v. Atlas Pipeline Partners, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania; and (e) Irving Feldbaum v. Atlas Pipeline Partners, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania, though the Tulsa Lawsuit has since been voluntarily dismissed. The Evnin, Greenthal, Welborn and Feldbaumlawsuits have been consolidated as In re Atlas Pipeline Partners, L.P. Unitholder Litigation, Case No. GD-14-019245, in the Court of Common Pleas for Allegheny County, Pennsylvania (the “Consolidated APL Lawsuit”). In October and November 2014, two public unitholders of ATLS (the “ATLS Plaintiffs” and, together with the APL Plaintiffs, the “Atlas Lawsuit Plaintiffs”) filed putative class action lawsuits against ATLS, ATLS GP, its managers, Targa and GP Merger Sub (the “ATLS Lawsuit Defendants” and, together with the APL Lawsuit Defendants, the “Atlas Lawsuit Defendants”). These lawsuits arewere styled (a) Rick Kane v. Atlas Energy, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania and (b) Jeffrey Ayers v. Atlas Energy, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania (the “ATLS Lawsuits”). The ATLS Lawsuits have been consolidated as In re Atlas Energy, L.P. Unitholder Litigation, Case No. GD-14-019658, in the Court of Common Pleas for Allegheny County, Pennsylvania (the “Consolidated ATLS Lawsuit” and, together with the Consolidated APL Lawsuit, the “Consolidated Atlas Lawsuits”), though the Kanelawsuit has since been voluntarily dismissed.
The Atlas Lawsuit Plaintiffs alleged a variety of causes of action challenging the Atlas mergers. Generally, the APL Plaintiffs alleged that (a) APL GP’s managers have breached the covenant of good faith and/or their fiduciary duties and (b) Targa, the Partnership, the general partner, MLP Merger Sub, APL, ATLS and APL GP have aided and abetted in these alleged breaches of the covenant of good faith and/or fiduciary duties. The APL Plaintiffs further alleged that (a) the premium offered to APL’s unitholders was inadequate, (b) APL agreed to contractual terms that would allegedly dissuade other potential acquirers from seeking to acquire APL, and (c) APL GP’s managers favored their self-interests over the interests of APL’s unitholders. The APL Plaintiffs in the Consolidated APL Lawsuit also alleged that the registration statement filed on November 19, 2014 failed, among other things, to disclose allegedly material details concerning (i) Stifel, Nicolaus & Company, Incorporated’s analysis of the Atlas mergers; (ii) APL and the Partnership’s financial projections; and (iii) the background of the Atlas mergers. Generally, the ATLS Plaintiffs alleged that (a) ATLS GP’s directors have breached the covenant of good faith and/or their fiduciary duties and (b) Targa, GP Merger Sub, and ATLS have aided and abetted in these alleged breaches of the covenant of good faith and/or fiduciary duties. The ATLS Plaintiffs further alleged that (a) the premium offered to the ATLS unitholders was inadequate, (b) ATLS agreed to contractual terms that would allegedly dissuade other potential acquirers from seeking to acquire ATLS, (c) ATLS GP’s directors favored their self-interests over the interests of the ATLS unitholders and (d) the registration statement failed to disclose allegedly material details concerning, among other things, (i) Wells Fargo Securities, LLC, Stifel, Nicolaus & Company, Incorporated, and Deutsche Bank Securities Inc.’s analyses of the Atlas mergers; (ii) the Partnership, Targa, APL, and ATLS’ financial projections; and (iii) the background of the Atlas mergers.
Based on these allegations, the Atlas Lawsuit Plaintiffs sought to enjoin the Atlas Lawsuit Defendants from proceeding with or consummating the Atlas mergers unless and until APL and ATLS adopted and implemented processes to obtain the best possible terms for their respective unitholders. The Atlas Lawsuit Plaintiffs also sought rescission, damages, and attorneys’ fees.
The parties to the Consolidated Atlas Lawsuits agreed to settle the Consolidated Atlas Lawsuits on February 9, 2015. In general, the settlements provide that in consideration for the dismissal of the Consolidated Atlas Lawsuits, ATLS and APL would provide supplemental disclosures regarding the Atlas mergers in a filing with the SEC on Form 8-K,
Environmental Proceedings
On June 18, 2015, the settlement notices to the putative class members have been submitted to the Court for approval.
Note 1716 — Supplemental Cash Flow Information
|
| Three Months Ended March 31, |
| |||||
|
| 2016 |
|
| 2015 |
| ||
Cash: |
|
|
|
|
|
|
|
|
Interest paid, net of capitalized interest (1) |
| $ | 77.3 |
|
| $ | 28.9 |
|
Income taxes paid, net of refunds |
|
| 1.1 |
|
|
| 0.1 |
|
Non-cash investing activities: |
|
|
|
|
|
|
|
|
Deadstock commodity inventory transferred to property, plant and equipment |
|
| 16.9 |
|
|
| — |
|
Impact of capital expenditure accruals on property, plant and equipment |
|
| 13.7 |
|
|
| 30.9 |
|
Transfers from materials and supplies inventory to property, plant and equipment |
|
| 0.5 |
|
|
| 0.6 |
|
Change in ARO liability and property, plant and equipment due to revised future ARO cash flow estimate |
|
| (9.1 | ) |
|
| 3.7 |
|
Non-cash financing activities: |
|
|
|
|
|
|
|
|
Cancellation of Treasury stock |
|
| (10.2 | ) |
|
|
|
|
Accrued distributions on unvested equity awards under share compensation arrangements |
|
| 0.2 |
|
|
| — |
|
Receivables from equity issuances |
|
| — |
|
|
| 24.6 |
|
Non-cash balance sheet movements related to Atlas Merger: (See Note 4 - Business Acquisitions) |
|
|
|
|
|
|
|
|
Non-cash merger consideration - common units and replacement equity awards |
|
| — |
|
|
| 2,583.5 |
|
Special GP Interest |
|
| — |
|
|
| 1,612.4 |
|
Current liabilities retained by Targa |
|
| — |
|
|
| (0.4 | ) |
Net non-cash balance sheet movements excluded from consolidated statements of cash flows |
|
| — |
|
|
| 4,195.5 |
|
Net cash merger consideration included in investing activities |
|
| — |
|
|
| 828.7 |
|
Total fair value of consideration transferred |
| $ | — |
|
| $ | 5,024.2 |
|
Nine Months Ended September 30, | ||||||||
2015 | 2014 | |||||||
Cash: | ||||||||
Interest paid, net of capitalized interest (1) | $ | 147.6 | $ | 88.2 | ||||
Income taxes paid, net of refunds | 4.1 | 2.2 | ||||||
Non-cash Investing and Financing balance sheet movements: | ||||||||
Debt additions and retirements related to exchange of TRP 6⅝% Notes for APL 6⅝% Notes | 342.1 | - | ||||||
Deadstock commodity inventories transferred to property, plant and equipment | 1.2 | 15.2 | ||||||
Reductions in Owner's Equity related to accrued distributions on unvested equity awards under share compensation arrangements | 1.1 | 2.0 | ||||||
Receivables from equity issuances | - | 0.4 | ||||||
Impact of capital expenditure accruals on property, plant and equipment | (57.2 | ) | (40.6 | ) | ||||
Transfers from materials and supplies inventory to property, plant and equipment | 2.9 | 2.7 | ||||||
Change in ARO liability and property, plant and equipment due to revised future ARO cash flow estimate | 3.8 | 2.1 | ||||||
Non-cash balance sheet movements related to business acquisition: (see Note 4 ): | ||||||||
Non-cash merger consideration - common units and replacement equity awards | $ | 2,583.5 | $ | - | ||||
Special GP Interest | 1,612.4 | - | ||||||
Current liabilities retained by Targa | (0.4 | ) | - | |||||
Net non-cash balance sheet movements excluded from consolidated statements of cash flows | 4,195.5 | - | ||||||
Net cash merger consideration included in investing activities | 828.7 | - | ||||||
Total fair value of consideration transferred | $ | 5,024.2 | $ | - |
(1) | Interest capitalized on major projects was |
Note 1817 — Segment Information
We report our operationsoperate in two divisions:primary segments (previously referred to as divisions): (i) Gathering and Processing, consistingand (ii) Logistics and Marketing (also referred to as the Downstream Business).
Concurrent with the completion of the TRC/TRP Merger, management reevaluated our reportable segments and determined that our previously disclosed divisions are the appropriate level of disclosure for our reportable segments. The increase in activity within Field Gathering and Processing due to the Atlas mergers coupled with the decline in activity in our 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 our Logistics and Marketing segment is no longer appropriate due to the integrated nature of the operations within our Downstream Business and its leadership by a consolidated executive management team. The Gathering and Processing division was previously disaggregated into two reportable segments – segments—(a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii)Processing. The Logistics and Marketing consisting ofdivision (also referred to as the Downstream Business) was previously disaggregated into two reportable segments – segments—(a) Logistics Assets and (b) Marketing and Distribution. The operating margin results of our commodity derivative activities are reported in Other.
Our Gathering and Processing divisionsegment 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 impuritiesimpurities; and assets used for crude oil gathering and terminaling. The Field Gathering and Processing segment's assets are located in the Permian Basin of West Texas and
32
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; and the Williston Basin in North Dakota. The Coastal GatheringDakota and Processing segment's assets are located in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico
Our Logistics and Marketing division is also referred to as our Downstream Business. Our Downstream Business 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, refined petroleum products and crude oil. It also includes certain natural gas supply and marketing activities in support of our other operations, including services to LPG exporters, as well as transporting natural gas and NGLs.
Three Months Ended September 30, 2015 | ||||||||||||||||||||||||||||
Field Gathering and Processing | Coastal Gathering and Processing | Logistics Assets | Marketing and Distribution | Other | Corporate and Eliminations | Total | ||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||||||
Sales of commodities | $ | 419.5 | $ | 50.8 | $ | 31.3 | $ | 797.9 | $ | 21.8 | $ | - | $ | 1,321.3 | ||||||||||||||
Fees from midstream services | 108.4 | 8.9 | 82.4 | 111.1 | - | - | 310.8 | |||||||||||||||||||||
527.9 | 59.7 | 113.7 | 909.0 | 21.8 | - | 1,632.1 | ||||||||||||||||||||||
Intersegment revenues | ||||||||||||||||||||||||||||
Sales of commodities | 195.8 | 57.6 | 3.2 | 67.3 | - | (323.9 | ) | - | ||||||||||||||||||||
Fees from midstream services | 2.4 | - | 64.6 | 5.4 | - | (72.4 | ) | - | ||||||||||||||||||||
198.2 | 57.6 | 67.8 | 72.7 | - | (396.3 | ) | - | |||||||||||||||||||||
Revenues | $ | 726.1 | $ | 117.3 | $ | 181.5 | $ | 981.7 | $ | 21.8 | $ | (396.3 | ) | $ | 1,632.1 | |||||||||||||
Operating margin | $ | 132.6 | $ | 7.9 | $ | 103.6 | $ | 60.2 | $ | 21.8 | $ | - | $ | 326.1 | ||||||||||||||
Other financial information: | ||||||||||||||||||||||||||||
Total assets (1) | $ | 10,088.7 | $ | 346.2 | $ | 1,854.0 | $ | 543.8 | $ | 137.6 | $ | 352.9 | $ | 13,323.2 | ||||||||||||||
Goodwill (2) | $ | 551.4 | $ | - | $ | - | $ | - | $ | - | $ | - | $ | 551.4 | ||||||||||||||
Capital expenditures | $ | 109.6 | $ | 5.5 | $ | 67.5 | $ | 0.9 | $ | - | $ | 2.7 | $ | 186.2 | ||||||||||||||
Business acquisition | $ | 5,024.2 | $ | - | $ | - | $ | - | $ | - | $ | - | $ | 5,024.2 |
Three Months Ended September 30, 2014 | ||||||||||||||||||||||||||||
Field Gathering | Coastal Gathering | Logistics Assets | Marketing and | Other | Corporate and | Total | ||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||||||
Sales of commodities | $ | 49.4 | $ | 83.4 | $ | 23.1 | $ | 1,855.6 | $ | (2.3 | ) | $ | - | $ | 2,009.2 | |||||||||||||
Fees from midstream services | 49.4 | 8.0 | 75.5 | 146.2 | - | - | 279.1 | |||||||||||||||||||||
98.8 | 91.4 | 98.6 | 2,001.8 | (2.3 | ) | - | 2,288.3 | |||||||||||||||||||||
Intersegment revenues | ||||||||||||||||||||||||||||
Sales of commodities | 386.0 | 143.6 | 1.3 | 116.1 | - | (647.0 | ) | - | ||||||||||||||||||||
Fees from midstream services | 1.7 | - | 85.9 | 10.1 | - | (97.7 | ) | - | ||||||||||||||||||||
387.7 | 143.6 | 87.2 | 126.2 | - | (744.7 | ) | - | |||||||||||||||||||||
Revenues | $ | 486.5 | $ | 235.0 | $ | 185.8 | $ | 2,128.0 | $ | (2.3 | ) | $ | (744.7 | ) | $ | 2,288.3 | ||||||||||||
Operating margin | $ | 98.0 | $ | 19.1 | $ | 118.6 | $ | 61.6 | $ | (2.3 | ) | $ | - | $ | 295.0 | |||||||||||||
Other financial information: | ||||||||||||||||||||||||||||
Total assets | $ | 3,359.0 | $ | 368.6 | $ | 1,650.2 | $ | 917.2 | $ | 6.7 | $ | 115.5 | $ | 6,417.2 | ||||||||||||||
Capital expenditures | $ | 74.0 | $ | 2.3 | $ | 59.8 | $ | 4.6 | $ | - | $ | 2.2 | $ | 142.9 |
Nine Months Ended September 30, 2015 | ||||||||||||||||||||||||||||
Field Gathering | Coastal Gathering | Logistics Assets | Marketing and | Other | Corporate and | Total | ||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||||||
Sales of commodities | $ | 1,021.4 | $ | 156.1 | $ | 89.4 | $ | 2,792.0 | $ | 60.7 | $ | - | $ | 4,119.6 | ||||||||||||||
Fees from midstream services | 277.8 | 25.1 | 259.9 | 328.8 | - | - | 891.6 | |||||||||||||||||||||
1,299.2 | 181.2 | 349.3 | 3,120.8 | 60.7 | - | 5,011.2 | ||||||||||||||||||||||
Intersegment revenues | ||||||||||||||||||||||||||||
Sales of commodities | 624.1 | 178.0 | 6.4 | 214.4 | - | (1,022.9 | ) | - | ||||||||||||||||||||
Fees from midstream services | 6.3 | - | 200.0 | 15.2 | - | (221.5 | ) | - | ||||||||||||||||||||
630.4 | 178.0 | 206.4 | 229.6 | - | (1,244.4 | ) | - | |||||||||||||||||||||
Revenues | $ | 1,929.6 | $ | 359.2 | $ | 555.7 | $ | 3,350.4 | $ | 60.7 | $ | (1,244.4 | ) | $ | 5,011.2 | |||||||||||||
Operating margin | $ | 349.9 | $ | 22.1 | $ | 341.7 | $ | 177.3 | $ | 60.7 | $ | - | $ | 951.7 | ||||||||||||||
Other financial information: | ||||||||||||||||||||||||||||
Total assets (1) | $ | 10,088.7 | $ | 346.2 | $ | 1,854.0 | $ | 543.8 | $ | 137.6 | $ | 352.9 | $ | 13,323.2 | ||||||||||||||
Goodwill (2) | $ | 551.4 | $ | - | $ | - | $ | - | $ | - | $ | - | $ | 551.4 | ||||||||||||||
Capital expenditures | $ | 345.2 | $ | 11.4 | $ | 199.6 | $ | 9.8 | $ | - | $ | 5.0 | $ | 571.0 | ||||||||||||||
Business acquisition | $ | 5,024.2 | $ | - | $ | - | $ | - | $ | - | $ | - | $ | 5,024.2 |
Nine Months Ended September 30, 2014 | ||||||||||||||||||||||||||||
Field Gathering | Coastal Gathering | Logistics Assets | Marketing and | Other | Corporate and | Total | ||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||||||
Sales of commodities | $ | 158.0 | $ | 273.7 | $ | 73.0 | $ | 5,361.0 | $ | (12.4 | ) | $ | - | $ | 5,853.3 | |||||||||||||
Fees from midstream services | 133.5 | 26.1 | 216.3 | 354.5 | - | - | 730.4 | |||||||||||||||||||||
291.5 | 299.8 | 289.3 | 5,715.5 | (12.4 | ) | - | 6,583.7 | |||||||||||||||||||||
Intersegment revenues | ||||||||||||||||||||||||||||
Sales of commodities | 1,168.2 | 484.0 | 2.7 | 383.6 | - | (2,038.5 | ) | - | ||||||||||||||||||||
Fees from midstream services | 3.9 | 0.1 | 224.5 | 25.5 | - | (254.0 | ) | - | ||||||||||||||||||||
1,172.1 | 484.1 | 227.2 | 409.1 | - | (2,292.5 | ) | - | |||||||||||||||||||||
Revenues | $ | 1,463.6 | $ | 783.9 | $ | 516.5 | $ | 6,124.6 | $ | (12.4 | ) | $ | (2,292.5 | ) | $ | 6,583.7 | ||||||||||||
Operating margin | $ | 289.8 | $ | 67.0 | $ | 324.0 | $ | 179.5 | $ | (12.4 | ) | $ | - | $ | 847.9 | |||||||||||||
Other financial information: | ||||||||||||||||||||||||||||
Total assets | $ | 3,359.0 | $ | 368.6 | $ | 1,650.2 | $ | 917.2 | $ | 6.7 | $ | 115.5 | $ | 6,417.2 | ||||||||||||||
Capital expenditures | $ | 301.4 | $ | 9.7 | $ | 195.9 | $ | 23.2 | $ | - | $ | 3.6 | $ | 533.8 |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Sales of commodities | ||||||||||||||||
Natural gas | $ | 456.1 | $ | 335.4 | $ | 1,201.6 | $ | 1,085.8 | ||||||||
NGL | 772.2 | 1,614.8 | 2,656.9 | 4,601.2 | ||||||||||||
Condensate | 40.4 | 38.6 | 113.1 | 108.7 | ||||||||||||
Petroleum products | 30.8 | 22.4 | 87.3 | 70.7 | ||||||||||||
Derivative activities | 21.8 | (2.0 | ) | 60.7 | (13.1 | ) | ||||||||||
1,321.3 | 2,009.2 | 4,119.6 | 5,853.3 | |||||||||||||
Fees from midstream services | ||||||||||||||||
Fractionating and treating | 55.7 | 55.3 | 160.1 | 153.5 | ||||||||||||
Storage, terminaling, transportation and export | 126.8 | 158.8 | 384.6 | 385.8 | ||||||||||||
Gathering and processing | 106.6 | 51.9 | 280.7 | 142.6 | ||||||||||||
Other | 21.7 | 13.1 | 66.2 | 48.5 | ||||||||||||
310.8 | 279.1 | 891.6 | 730.4 | |||||||||||||
Total revenues | $ | 1,632.1 | $ | 2,288.3 | $ | 5,011.2 | $ | 6,583.7 |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Reconciliation of operating margin to net income: | ||||||||||||||||
Operating margin | $ | 326.1 | $ | 295.0 | $ | 951.7 | $ | 847.9 | ||||||||
Depreciation and amortization expense | (165.8 | ) | (87.5 | ) | (448.3 | ) | (252.8 | ) | ||||||||
General and administrative expense | (42.9 | ) | (40.4 | ) | (130.1 | ) | (115.3 | ) | ||||||||
Interest expense, net | (64.1 | ) | (36.0 | ) | (177.2 | ) | (104.1 | ) | ||||||||
Other, net | (0.4 | ) | 8.4 | (11.3 | ) | 18.5 | ||||||||||
Income tax (expense)/benefit | 0.4 | (1.3 | ) | (0.4 | ) | (3.7 | ) | |||||||||
Net income | $ | 53.3 | $ | 138.2 | $ | 184.4 | $ | 390.5 |
Logistics Assets segment is involved in transporting, storing, and fractionating mixed NGLs; storing, terminaling, and transporting finished NGLs, including services for exporting LPGs; and storing and terminaling of refined petroleum products. These assetsMarketing operations are generally connected to and supplied in part by our Gathering and Processing segments and are predominantly located in Mont Belvieu and Galena Park, Texas, in Lake Charles, Louisiana and in Tacoma, Washington.
Other contains the results (including any hedge ineffectiveness) of the Partnership’s commodity derivative activities included in operating marginmargin. and the mark-to-market gains/losses related to derivative contracts that were not designated as cash-flowcash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column.
Reportable segment information is shown in the following tables:
|
| Three Months Ended March 31, 2016 |
| |||||||||||||||||
|
| Gathering and Processing |
|
| Logistics and Marketing |
|
| Other |
|
| Corporate and Eliminations |
|
| Total |
| |||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
| $ | 110.3 |
|
| $ | 1,033.9 |
|
| $ | 26.8 |
|
| $ | — |
|
| $ | 1,171.0 |
|
Fees from midstream services |
|
| 115.8 |
|
|
| 155.6 |
|
|
| — |
|
|
| — |
|
|
| 271.4 |
|
|
|
| 226.1 |
|
|
| 1,189.5 |
|
|
| 26.8 |
|
|
| — |
|
|
| 1,442.4 |
|
Intersegment revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
|
| 412.6 |
|
|
| 47.3 |
|
|
| — |
|
|
| (459.9 | ) |
|
| — |
|
Fees from midstream services |
|
| 2.1 |
|
|
| 4.1 |
|
|
| — |
|
|
| (6.2 | ) |
|
| — |
|
|
|
| 414.7 |
|
|
| 51.4 |
|
|
| — |
|
| $ | (466.1 | ) |
| $ | — |
|
Revenues |
| $ | 640.8 |
|
| $ | 1,240.9 |
|
| $ | 26.8 |
|
| $ | (466.1 | ) |
| $ | 1,442.4 |
|
Operating margin |
| $ | 115.6 |
|
| $ | 157.0 |
|
| $ | 26.8 |
|
| $ | — |
|
| $ | 299.4 |
|
Other financial information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets (1) |
| $ | 10,219.0 |
|
| $ | 2,501.0 |
|
| $ | 105.7 |
|
| $ | 42.9 |
|
| $ | 12,868.6 |
|
Goodwill (2) |
| $ | 393.0 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 393.0 |
|
Capital expenditures |
| $ | 103.0 |
|
| $ | 73.1 |
|
| $ | — |
|
| $ | 0.8 |
|
| $ | 176.9 |
|
(1) | Corporate assets at the Segment level primarily include tax-related assets, cash and prepaids. |
(2) | Total assets include goodwill. Goodwill has been attributed to our Gathering and Processing segment. |
|
| Three Months Ended March 31, 2015 |
| |||||||||||||||||
|
| Gathering and Processing |
|
| Logistics and Marketing |
|
| Other |
|
| Corporate and Eliminations |
|
| Total |
| |||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
| $ | 220.9 |
|
| $ | 1,159.7 |
|
| $ | 21.7 |
|
| $ | (0.1 | ) |
| $ | 1,402.2 |
|
Fees from midstream services |
|
| 72.0 |
|
|
| 205.4 |
|
|
| — |
|
|
| 0.1 |
|
|
| 277.5 |
|
|
|
| 292.9 |
|
|
| 1,365.1 |
|
|
| 21.7 |
|
| $ | — |
|
| $ | 1,679.7 |
|
Intersegment revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
|
| 278.1 |
|
|
| 55.9 |
|
|
| — |
|
|
| (334.0 | ) |
|
| — |
|
Fees from midstream services |
|
| 2.0 |
|
|
| 4.5 |
|
|
| — |
|
|
| (6.5 | ) |
|
| — |
|
|
|
| 280.1 |
|
|
| 60.4 |
|
|
| — |
|
| $ | (340.5 | ) |
| $ | — |
|
Revenues |
| $ | 573.0 |
|
| $ | 1,425.5 |
|
| $ | 21.7 |
|
| $ | (340.5 | ) |
| $ | 1,679.7 |
|
Operating margin |
| $ | 87.0 |
|
| $ | 191.3 |
|
| $ | 21.7 |
|
| $ | — |
|
| $ | 300.0 |
|
Other financial information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets (1) |
| $ | 10,671.8 |
|
| $ | 2,302.5 |
|
| $ | 177.3 |
|
| $ | 39.2 |
|
| $ | 13,190.8 |
|
Goodwill (2) |
| $ | 557.9 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 557.9 |
|
Capital expenditures |
| $ | 95.5 |
|
| $ | 60.7 |
|
| $ | — |
|
| $ | 1.1 |
|
| $ | 157.3 |
|
Business acquisition |
| $ | 5,024.2 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 5,024.2 |
|
(1) | Corporate assets at the Segment level primarily include tax-related assets, cash and prepaids. |
(2) | Total assets include goodwill. Goodwill has been attributed to our Gathering and Processing segment. |
The following table shows our consolidated revenues by product and service for the periods presented:
|
| Three Months Ended March 31, |
| |||||
|
| 2016 |
|
| 2015 |
| ||
Sales of commodities: |
|
|
|
|
|
|
|
|
Natural gas |
| $ | 326.9 |
|
| $ | 302.1 |
|
NGL |
|
| 785.5 |
|
|
| 1,030.7 |
|
Condensate |
|
| 22.2 |
|
|
| 21.3 |
|
Petroleum products |
|
| 9.6 |
|
|
| 26.4 |
|
Derivative activities |
|
| 26.8 |
|
|
| 21.7 |
|
|
|
| 1,171.0 |
|
|
| 1,402.2 |
|
Fees from midstream services: |
|
|
|
|
|
|
|
|
Fractionating and treating |
|
| 30.2 |
|
|
| 49.8 |
|
Storage, terminaling, transportation and export |
|
| 118.4 |
|
|
| 136.2 |
|
Gathering and processing |
|
| 105.0 |
|
|
| 68.4 |
|
Other |
|
| 17.8 |
|
|
| 23.1 |
|
|
|
| 271.4 |
|
|
| 277.5 |
|
Total revenues |
| $ | 1,442.4 |
|
| $ | 1,679.7 |
|
34
The following table shows a reconciliation of operating margin to net income (loss) for the periods presented:
|
| Three Months Ended March 31, |
| |||||
|
| 2016 |
|
| 2015 |
| ||
Reconciliation of operating margin to net income: |
|
|
|
|
|
|
|
|
Operating margin |
| $ | 299.4 |
|
| $ | 300.0 |
|
Depreciation and amortization expense |
|
| (193.5 | ) |
|
| (118.6 | ) |
General and administrative expense |
|
| (43.4 | ) |
|
| (40.2 | ) |
Goodwill impairment |
|
| (24.0 | ) |
|
| - |
|
Interest expense, net |
|
| (46.9 | ) |
|
| (50.0 | ) |
Other, net |
|
| 18.8 |
|
|
| (12.3 | ) |
Income tax expense |
|
| 0.2 |
|
|
| (1.1 | ) |
Net income |
| $ | 10.6 |
|
| $ | 77.8 |
|
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in our Annual Report on Form 10-K for the year ended December 31, 2015 (“Annual Report”), as well as the unaudited consolidated financial statements and Notes hereto included in this Quarterly Report on Form 10-Q.
Overview
Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by TRC. Our common units were listed on the NYSE under the symbol “NGLS.” Our Preferred Units are reviewinglisted on the NYSE under the symbol “NGLS PRA.”
Targa Resources GP LLC, our segment disclosures asgeneral partner, is a resultDelaware limited liability company formed by Targa in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly owned subsidiary of the merger and integration efforts related to the Atlas mergers.
On February 27, 2015, (i) Targa17, 2016, TRC completed the previously announced transactions contemplated by the ATLS Merger Agreement, by and (ii) Targaamong us, our general partner, TRC and the Partnership completed the previously announced transactions contemplated by the APL Merger Agreement. PursuantSub pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the ATLS Merger Agreement, GP Merger Sub merged with and into ATLS,TRP, with ATLSTRP continuing as the surviving entity and as a subsidiary of Targa, whichTRC. Following the closing of the TRC/TRP Merger on February 17, 2016, TRC owns all of our outstanding common units.
Our Operations
We are a leading United States provider of midstream natural gas and NGL services, with a growing presence in crude oil gathering and petroleum terminaling. Our Common units were listed on the NYSE under the symbol “NGLS” prior to TRC's acquisition on February 17, 2016 of all of our outstanding common units on that it and its subsidiaries did not already own. Our 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.”
We are 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. |
To provide these services, we referoperate in two primary segments (previously referred to as divisions): (i) Gathering and Processing, previously disaggregated into two reportable segments—(i) Gathering and Processing and (ii) Logistics and Marketing (also referred to as the ATLS merger. PursuantDownstream Business).
Concurrent with the completion of the TRC/TRP Merger, management reevaluated our reportable segments and determined that our previously disclosed divisions are the appropriate level of disclosure for our reportable segments. The increase in activity within Field
35
Gathering and Processing due to the termsAtlas mergers coupled with the decline in activity in our Gulf Coast region makes the disaggregation of Field Gathering and conditions set forth inProcessing and Coastal Gathering and Processing no longer warranted. Management also determined that further disaggregation of our Logistics and Marketing segment is no longer appropriate due to the APL Merger Agreement, MLP Merger Sub merged with and into APL, with APL continuing as the surviving entity and as a subsidiaryintegrated nature of the Partnership, which we referoperations within our Downstream Business and its leadership by a consolidated executive management team. The Gathering and Processing division was previously disaggregated into two reportable segments—(a) Field Gathering and Processing and (b) Coastal Gathering and Processing. The Logistics and Marketing division (also referred to as the APL mergerDownstream Business) was previously disaggregated into two reportable segments—(a) Logistics Assets and together with(b) Marketing and Distribution.
Our Gathering and Processing segment includes assets used in the ATLS merger, the Atlas mergers.
Our 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 our other businesses including services to LPG exporters. It also includes certain natural gas supply and marketing activities in support of our other operations, as well as transporting natural gas and NGLs.
The Atlas mergers add TPL’s Woodford/SCOOP, Mississippi Lime, Eagle FordLogistics and additional Permian assetsMarketing operations are generally connected to the Partnership’s existing operations. In total,
Other contains the IDR Giveback Amendment entered intoresults (including any hedge ineffectiveness) of our commodity derivative activities which are included in conjunction with the Atlas mergers, IDRsoperating margin.
2016 Developments
Volatility of $9.375 million were allocated to common unitholdersCommodity Prices
Fluctuations in energy prices can greatly affect production rates and investments by third parties in the first, seconddevelopment and third quartersproduction of 2015.new oil and natural gas reserves. Drilling and production activity generally decreases as crude oil and natural gas prices decrease below commercially acceptable levels. Prices of oil and natural gas have been historically volatile, and we expect this volatility to continue. Our operations are affected by the level of crude, natural gas and NGL prices, the relationship among these prices and related reduced activity levels from our customers. The IDR Giveback Amendment covers sixteen quarters following the completionduration and magnitude of the Atlas mergers on February 27, 2015 and will resultdecline in reallocation of IDR payments to common unitholders at the following amounts - $9.375 million per quarter for 2015, $6.25 million per quarter for 2016, $2.5 million per quarter for 2017 and $1.25 million per quarter for 2018.
Logistics and Marketing Segment Expansion
Cedar Bayou Fractionator Train 5
In July 2014, we approved construction of a 100 MBbl/d fractionator at our 88%-owned Cedar Bayou Fractionator (“CBF”) in Mont Belvieu, Texas.CBF. The 100 MBbl/d expansion will be fully integrated with ourthe Partnership’s existing Gulf Coast NGL storage, terminaling and delivery infrastructure, which includes an extensive network of connections to key petrochemical and industrial customers as well as our LPG export terminal at Galena Park on the Houston Ship Channel. All environmentalConstruction has been underway and internal approvals required to commence construction of the expansion are in place, construction is underwaycontinuing and we expect completion of construction in mid-2016.the second quarter of 2016. Construction of the expansion will proceedhas proceeded without disruption to existing operations, and we estimate that total growth capital expenditures net to our 88% interest for the expansion and the related infrastructure enhancements at Mont Belvieu should approximate $385$340 million.
Channelview Splitter
On December 27, 2015, we and Noble entered into the Splitter Agreement under which we will build and operate a 35,000 barrel per day crude and condensate splitter at our Channelview Terminal on the Houston Ship Channel (“Channelview Splitter”). The Channelview Splitter will have the capability to split approximately 35,000 barrels per day of condensate into its various components, including naphtha, kerosene, gas oil, jet fuel, and liquefied petroleum gas and will provide segregated storage for the crude, condensate and components. The Channelview Splitter is expected to be completed by early 2018, and has an estimated total cost of approximately $140 million. As contemplated by the December 2014 Agreement, the Splitter Agreement completes and terminates the December 2014 Agreement while retaining the Partnership’s economic benefits from that agreement.
36
Permian Basin Buffalo Plant
In April 2014, TPL announced plans to build a new plant and expand the gathering footprint of its WestTX system. This project includes the laying of a new high pressure gathering line into Martin and Andrews counties of Texas, as well as incremental compression and a new 200 MMcf/d cryogenic processing plant, known as the Buffalo plant, which commenced commercial operations in April 2016. Total net growth capital expenditures for the Buffalo plant should approximate $105 million.
Eagle Ford Shale Natural Gas Processing Joint Venture
In October 5, 2015, we announced that we have entered into joint venture agreements with Sanchez Energy Corporation (“Sanchez”) to construct a new 200 MMcf/200MMcf/d cryogenic natural gas processing plant in La Salle County, Texas (“La Salle County(the “Raptor Plant”). and approximately 45 miles of associated pipelines. We expect to invest approximately $125 million of growth capex related to the joint ventures, and assuming full contribution from Sanchez Energy, will haveown a 50% ownership interest in the plant and the approximately 45 miles of high pressure gathering pipelines that will connect Sanchez's Catarina gathering system to the plant. We will hold alla portion of the transportation capacity on the pipeline, and will pay the gathering joint venture receives fees for transportation.
The La Salle CountyRaptor Plant is expected towill accommodate the growing production from Sanchez’s premier Eagle Ford Shale acreage position in Dimmit, La Salle and Webb Counties, Texas and from other third party producers. The plant and high pressure gathering lines are supported by long-term, firm, fee-based contracts and acreage dedications with Sanchez. We will manage construction and operations of the plant and high pressure gathering lines, and the plant is expected to begin operations in early 2017. Prior to the plant being placed in service,in-service, we expect to benefit from Sanchez’sSanchez natural gas volumes that will beare processed at our Silver Oak facilities in Bee County, Texas.
In addition to the first quarter of 2015,major projects in process noted above, we completed the 40 MMcf/d Little Missouri 3 plant expansion in McKenzie County, North Dakota, that increased capacity to 90 MMcf/d.
Financing Activities
During the commodity price environment and will continuequarter ended March 31, 2016, we repurchased on the open market a portion of our outstanding senior notes paying $330.6 million plus accrued interest to adjust our growth capital expenditure programs to meet expected producer requirements.
We may retire or equity securities.
Recent Accounting Pronouncements
In February 2015,May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The update also creates a new Subtopic 340-40, Other Assets and Deferred Costs – Contracts with Customers, which provides guidance for the incremental costs of obtaining a contract with a customer and those costs incurred in fulfilling a contract with a customer that are not in the scope of another topic. The new revenue standard requires that entities should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entities expect to be entitled in exchange for those goods or services. To achieve that core principle, the standard requires a five step process of identifying the contracts with customers, identifying the performance obligations in the contracts, determining the transaction price, allocating the transaction price to the performance obligations, and recognizing revenue when, or as, the performance obligations are satisfied. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.
With the issuance in August 2015 of ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, the revenue recognition standard is effective for the annual period beginning after December 15, 2017, and for annual and interim periods thereafter. Earlier adoption is permitted for annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We must retroactively apply the new revenue recognition standard to transactions in all prior periods presented, but will have a choice between either (1) restating each prior period presented or (2)
37
presenting a cumulative effect adjustment in the period the amendment is adopted. We expect to adopt this guidance on January 1, 2018 and are continuing to evaluate the impact on our revenue recognition practices.
In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The amendments are intended to simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities and modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities. The amendments are effective for us in 2016 with early adoption permitted. We are currently evaluating the effectno impact on our consolidated financial statement or results of the amendments for each of our less-than-wholly owned subsidiaries.
In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The amendments in this update require that debt issuance costs related to a recognized debt liability (other than line-of-credit or other revolving credit facilities) be presented in the consolidated balance sheetConsolidated Balance Sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This update dealsdealt solely with financial statement display matters; recognition and measurement of debt issuance costs arewere unaffected. UnamortizedWe adopted the amendments on January 1, 2016 and have reclassified unamortized debt issuance costs of $40.2$38.3 million and $29.9 million for term loans and notes were included inon our Consolidated Balance Sheet as of December 31, 2015 from Other long-term assets on theto Long-term debt to conform to current year presentation. Our Consolidated Balance SheetsSheet as of September 30, 2015 and DecemberMarch 31, 2014. 2016 has $34.0 million in unamortized debt issuance costs classified in Long-term debt.
In August 2015,February 2016, the FASB issued ASU 2015-15,2016-02, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit ArrangementsLeases (Topic 842). The amendment clarifies ASU 2015-03 and provides that an entity may defer and present debt issuance costs for a line-of-credit or other revolving credit facility arrangement as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the arrangement. Unamortized debt issuance costs of $6.5 million and $7.6 million for revolving credit facilities were included in Other long-term assets on the Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014. We will continue to include debt issuance costs for our line-of-credit and revolving credit facility arrangements in Other long-term assets upon adoption of ASU 2015-03. We plan to adopt these standards as of December 31, 2015.
In August 2015,March 2016, the FASB issued ASU 2015-14,2016-08, Revenue from Contracts with Customers (Topic 606): DeferralPrincipal versus Agent Considerations. The amendments in this update improve the operability and understandability of the Effective Date. The amendment defers theimplementation guidance on principal versus agent considerations, including clarifying that an entity should determine whether it is a principal or an agent for each specified good or service promised to a customer. These amendments are effective date of ASU 2014-09, Revenue from Contracts with Customers (Topic 606) by one year. As a result of the amendment, Topic 606 is effective for the annual period beginning December 15, 2017, and for annualfiscal years, and interim periods thereafter,within those years, beginning on or after December 15, 2017, with early adoption permitted. Earlier adoption is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We expect to adopt this guidance on January 1, 2018 and are continuing to evaluate the impact of Topic 606 on our revenue recognition practices.
In September 2015,March 2016, the FASB issued ASU 2015-16, 2016-09,Business Combinations Compensation-Stock Compensation (Topic 805)718): Simplifying theImprovements to Employee Share-Based Payment Accounting for Measurement-Period Adjustments. Topic 805 currently requires that adjustments to provisional amounts recorded in a business combination be recognized retrospectively as if the accounting had been completed at the acquisition date. The amendments in this update requireprovides, among other things, that an acquirer recognize these measurement-period adjustments(1) all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit in the income statement with the tax effects of exercised or vested awards treated as discrete items in the reporting period in which they occur and recognition of excess tax benefits regardless of whether the adjustment amounts are determined,benefit reduces taxes payable in the current period; (2) excess tax benefits should be classified along with the effect on earnings of changes in depreciation, amortization, or other income effects, if any,tax cash flows as an operating activity; (3) an entity can make an entity-wide accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur; (4) the threshold to qualify for equity classification permits withholding up to the maximum statutory tax rates in the applicable jurisdictions; and (5) cash paid by an employer when directly withholding shares for tax-withholding purposes should be classified as a resultfinancing activity on the statement of the changecash flows.
Amendments related to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments require disclosuretiming of the amount recorded in current-period earnings that would have been recorded in previous reporting periods if thewhen excess tax benefits are recognized, minimum statutory withholding requirements, forfeitures, and intrinsic value should be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to the provisional amounts had been recognizedequity as of the acquisition date.beginning of the period in which the guidance is adopted. Amendments related to the presentation of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirement should be applied retrospectively. Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statement and the practical expedient for estimating expected term should be applied prospectively. An entity may elect to apply the amendments related to the presentation of excess tax benefits on the statement of cash flows using either a prospective transition method or a retrospective transition method. We expect to adopt the amendments in the second quarter of 2016 and are currently evaluating the impacts of the amendments to our financial statements and accounting practices for stock compensation.
In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. These amendments clarify the guidance on identification of performance obligations and licensing. The amendments include that entities do not have to decide if goods and services are effective for usperformance obligations if they are considered immaterial in 2016, with early adoption permitted. We adopted the amendments on September 30, 2015 and have recognized the measurement-period adjustmentscontext of a contract. Entities are also permitted to account for the Atlas mergers determined inshipping and handling that takes place after the three months ended September 30, 2015 in current period earnings. See Note 4 for additional information regarding the nature and amountcustomer has gained control of the measurement-period adjustments.goods as actions to fulfill the contract rather than separate services. In order to identify a performance obligation in a customer contract, an entity has to determine whether the goods or services are distinct, and ASU No.
38
2016-10 clarifies how the determination can be made. We expect to adopt this guidance on January 1, 2018 and are continuing to evaluate the impact on our revenue recognition practices.
How We Evaluate Our Operations
The profitability of our business segments is a function of the difference between: (i) the revenues we receive from our operations, including fee-based revenues from services and revenues from the natural gas, NGLs, crude oil and condensate we sell, and (ii) the costs associated with conducting our operations, including the costs of wellhead natural gas, crude oil and mixed NGLs that we purchase as well as operating, general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for crude oil, natural gas and NGLs and the volumes of crude oil, natural gas and NGL throughput on our systems are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services, utilization of our assets and changes in our customer mix.
Our profitability is also impacted by fee-based revenues. Our growth strategy, based on expansion of existing facilities as well as third-party acquisitions of businesses and assets, has increased the percentage of our revenues that are fee-based. Fixed fees for services such as fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities.
Management uses a variety of financial measures and operational measurements to analyze our performance. These include: (1) throughput volumes, facility efficiencies and fuel consumption, (2) operating expenses (3) capital expenditures and (4) the following non-GAAP measures: gross margin and operating margin, adjusted EBITDA and distributable cash flow.
Throughput Volumes, Facility Efficiencies and Fuel Consumption
Our profitability is impacted by our ability to add new sources of natural gas supply and crude oil supply to offset the natural decline of existing volumes from oil and natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing crude oil and natural gas supplies currently gathered by third-parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, typically connected by third-party transportation, to our Downstream Business’ fractionation facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL supply from third-party facilities.
In addition, we seek to increase operating margin by limiting volume losses, reducing fuel consumption and by increasing efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes received at the wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. We also monitor the volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants and Downstream Business facilities to determine customer settlements for sales and volume related fees for service and helps us increase efficiency and reduce fuel consumption.
As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of our facilities. Similar tracking is performed for our crude oil gathering and logistics assets. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis and safety programs.
Operating Expenses
Operating expenses are costs associated with the operation of specific assets. Labor, contract services, repair and maintenance, utilities and ad valorem taxes comprise the most significant portion of our operating expenses. These expenses, other than fuel and power, generally remain relatively stable and independent of the volumes through our systems, but fluctuate depending on the scope of the activities performed during a specific period.
Capital Expenditures
Capital projects associated with growth and maintenance projects are closely monitored. Return on investment is analyzed before a capital project is approved, spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approval. We have seen a substantial increase in our total capital spent since 2010 and currently have significant internal growth projects.
We define gross margin as revenues less purchases. It is impacted by volumes and commodity prices as well as by our contract mix and commodity hedging program. We define
Gathering and Processing segment gross margin as total operatingconsists primarily of revenues from (1) the sale of natural gas, condensate, crude oil and NGLs and (2)fee revenues related to natural gas and crude oil gathering and service fee revenues,services, less product purchases, which consist primarily of producer payments and other natural gas and crude oil purchases.
Logistics Assetsand Marketing segment gross margin consists primarily of service fee revenue. Gross margin for Marketing and Distribution equals total revenue from service fees, NGL and natural gas sales, less cost of sales, which consists primarily of NGL and natural gas purchases, transportation costs and changes in inventory valuation.
· | service fee revenues (including the pass-through of energy costs included in fee rates), |
· | system product gains and losses, and |
· | NGL and natural gas sales, less NGL and natural gas purchases, transportation costs and the net inventory change. |
The gross margin impacts of cash flow hedge settlements are reported in Other.
Operating Margin
We define operating margin as gross margin less operating expenses. Operating margin is an important performance measure of the core profitability of our operations.
Management reviews business segment gross margin and operating margin monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that our 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 usmanagement and by external users of our financial statements, including investors and commercial banks, to assess:
· | the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; |
· | our 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. |
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 our 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 our industry, our definitions of gross margin and operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
40
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.
| Three Months Ended March 31, |
| |||||||
| 2016 |
|
| 2015 |
| ||||
| (In millions) |
| |||||||
Reconciliation of Targa Resources Partners gross |
|
|
|
|
|
|
|
|
|
margin and operating margin to net income: |
|
|
|
|
|
|
|
|
|
Gross margin |
| $ | 431.4 |
|
|
| $ | 421.1 |
|
Operating expenses |
|
| (132.0 | ) |
|
|
| (121.1 | ) |
Operating margin |
|
| 299.4 |
|
|
|
| 300.0 |
|
Depreciation and amortization expenses |
|
| (193.5 | ) |
|
|
| (118.6 | ) |
General and administrative expenses |
|
| (43.4 | ) |
|
|
| (40.2 | ) |
Goodwill impairment |
|
| (24.0 | ) |
|
|
| - |
|
Interest expense, net |
|
| (46.9 | ) |
|
|
| (50.0 | ) |
Income tax expense |
|
| 0.2 |
|
|
|
| (1.1 | ) |
Gain (loss) on sale or disposition of assets |
|
| (0.9 | ) |
|
|
| (0.6 | ) |
Gain (loss) from financing activities |
|
| 24.7 |
|
|
|
| - |
|
Other, net |
|
| (5.0 | ) |
|
|
| (11.7 | ) |
Net income (loss) |
| $ | 10.6 |
|
|
| $ | 77.8 |
|
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
(In millions) | ||||||||||||||||
Reconciliation of Targa Resources Partners LP gross margin and operating margin to net income: | ||||||||||||||||
Gross margin | $ | 459.7 | $ | 407.8 | $ | 1,333.5 | $ | 1,171.5 | ||||||||
Operating expenses | (133.6 | ) | (112.8 | ) | (381.8 | ) | (323.6 | ) | ||||||||
Operating margin | 326.1 | 295.0 | 951.7 | 847.9 | ||||||||||||
Depreciation and amortization expenses | (165.8 | ) | (87.5 | ) | (448.3 | ) | (252.8 | ) | ||||||||
General and administrative expenses | (42.9 | ) | (40.4 | ) | (130.1 | ) | (115.3 | ) | ||||||||
Interest expense, net | (64.1 | ) | (36.0 | ) | (177.2 | ) | (104.1 | ) | ||||||||
Income tax (expense) benefit | 0.4 | (1.3 | ) | (0.4 | ) | (3.7 | ) | |||||||||
Gain on sale or disposition of assets | - | 4.4 | 0.2 | 5.6 | ||||||||||||
(Loss) from financing activities | (0.5 | ) | - | (0.5 | ) | - | ||||||||||
Other, net | 0.1 | 4.0 | (11.0 | ) | 12.9 | |||||||||||
Net income | $ | 53.3 | $ | 138.2 | $ | 184.4 | $ | 390.5 |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
(In millions) | ||||||||||||||||
Reconciliation of Net Income to Adjusted EBITDA: | ||||||||||||||||
Net income attributable to Targa Resources Partners LP | $ | 48.5 | $ | 128.3 | $ | 167.1 | $ | 359.6 | ||||||||
Interest expense, net | 64.1 | 36.0 | 177.2 | 104.1 | ||||||||||||
Income tax expense (benefit) | (0.4 | ) | 1.3 | 0.4 | 3.7 | |||||||||||
Depreciation and amortization expenses | 165.8 | 87.5 | 448.3 | 252.8 | ||||||||||||
Gain on sale or disposition of assets | - | (4.4 | ) | (0.2 | ) | (5.6 | ) | |||||||||
Loss from financing activities | 0.5 | - | 0.5 | - | ||||||||||||
(Earnings) loss from unconsolidated affiliates (1) | 1.6 | (4.7 | ) | 1.1 | (13.8 | ) | ||||||||||
Distributions from unconsolidated affiliates (1) | 4.2 | 4.7 | 11.2 | 13.8 | ||||||||||||
Compensation on TRP equity grants (1) | 3.9 | 2.1 | 12.8 | 7.0 | ||||||||||||
Transaction costs related to business acquisitions (1) | 0.6 | - | 14.9 | - | ||||||||||||
Risk management activities | 21.8 | 1.5 | 46.0 | 0.9 | ||||||||||||
Other | - | - | 0.6 | - | ||||||||||||
Noncontrolling interests adjustment (2) | (4.8 | ) | (3.5 | ) | (13.4 | ) | (10.4 | ) | ||||||||
Targa Resources Partners LP Adjusted EBITDA | $ | 305.8 | $ | 248.8 | $ | 866.5 | $ | 712.1 |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
(In millions) | ||||||||||||||||
Reconciliation of net cash provided by Targa Resources Partners LP operating activities to Adjusted EBITDA: | ||||||||||||||||
Net cash provided by operating activities | $ | 215.5 | $ | 114.9 | $ | 737.8 | $ | 571.8 | ||||||||
Net income attributable to noncontrolling interests | (4.8 | ) | (9.9 | ) | (17.3 | ) | (30.9 | ) | ||||||||
Interest expense | 64.1 | 36.0 | 177.2 | 104.1 | ||||||||||||
Non-cash interest expense, net (1) | (3.3 | ) | (2.2 | ) | (9.3 | ) | (8.8 | ) | ||||||||
(Earnings) loss from unconsolidated affiliates (2) | 1.6 | (4.7 | ) | 1.1 | (13.8 | ) | ||||||||||
Distributions from unconsolidated affiliates (2) | 4.2 | 4.7 | 11.2 | 13.8 | ||||||||||||
Transaction costs related to business acquisitions (2) | 0.6 | - | 14.9 | - | ||||||||||||
Current income tax expense | 0.2 | 0.9 | 0.7 | 2.6 | ||||||||||||
Other (3) | (10.8 | ) | (4.6 | ) | (35.1 | ) | (13.7 | ) | ||||||||
Changes in operating assets and liabilities which used (provided) cash: | ||||||||||||||||
Accounts receivable and other assets | 46.7 | 114.8 | (157.9 | ) | 155.9 | |||||||||||
Accounts payable and other liabilities | (8.2 | ) | (1.1 | ) | 143.2 | (68.9 | ) | |||||||||
Targa Resources Partners LP Adjusted EBITDA | $ | 305.8 | $ | 248.8 | $ | 866.5 | $ | 712.1 |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
(In millions) | (In millions) | |||||||||||||||
Reconciliation of net income to Distributable Cash flow: | ||||||||||||||||
Net income attributable to Targa Resources Partners LP | $ | 48.5 | $ | 128.3 | $ | 167.1 | $ | 359.6 | ||||||||
Depreciation and amortization expenses | 165.8 | 87.5 | 448.3 | 252.8 | ||||||||||||
Deferred income tax expense (benefit) | (0.6 | ) | 0.4 | (0.3 | ) | 1.1 | ||||||||||
Non-cash interest expense, net (1) | 3.3 | 2.2 | 9.3 | 8.8 | ||||||||||||
Loss from financing activities | 0.5 | - | 0.5 | - | ||||||||||||
(Earnings) loss from unconsolidated affiliates (2) | 1.6 | (4.7 | ) | 1.1 | (13.8 | ) | ||||||||||
Distributions from unconsolidated affiliates (2) | 4.2 | 4.7 | 11.2 | 13.8 | ||||||||||||
Compensation on TRP equity grants (2) | 3.9 | 2.1 | 12.8 | 7.0 | ||||||||||||
Gain on sale or disposition of assets | - | (4.4 | ) | (0.2 | ) | (5.6 | ) | |||||||||
Risk management activities | 21.8 | 1.5 | 46.0 | 0.9 | ||||||||||||
Maintenance capital expenditures | (26.7 | ) | (21.9 | ) | (73.0 | ) | (55.6 | ) | ||||||||
Transactions costs related to business acquisitions (2) | 0.6 | - | 14.9 | - | ||||||||||||
Other (3) | (2.2 | ) | (1.1 | ) | (6.9 | ) | (5.0 | ) | ||||||||
Targa Resources Partners LP distributable cash flow | $ | 220.7 | $ | 194.6 | $ | 630.8 | $ | 564.0 |
The following table and discussion is a summary of our consolidated results of operations:
|
| Three Months Ended March 31, |
|
|
|
|
|
|
|
|
|
| |||||
|
| 2016 |
|
| 2015 |
|
| 2016 vs. 2015 |
|
| |||||||
| ($ in millions, except operating statistics and price amounts) | ||||||||||||||||
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
| $ | 1,171.0 |
|
| $ | 1,402.2 |
|
| $ | (231.2 | ) |
|
| 16 | % |
|
Fees from midstream services |
|
| 271.4 |
|
|
| 277.5 |
|
|
| (6.1 | ) |
|
| 2 | % |
|
Total revenues |
|
| 1,442.4 |
|
|
| 1,679.7 |
|
|
| (237.3 | ) |
|
| 14 | % |
|
Product purchases |
|
| 1,011.0 |
|
|
| 1,258.6 |
|
|
| (247.6 | ) |
|
| 20 | % |
|
Gross margin (1) |
|
| 431.4 |
|
|
| 421.1 |
|
|
| 10.3 |
|
|
| 2 | % |
|
Operating expenses |
|
| 132.0 |
|
|
| 121.1 |
|
|
| 10.9 |
|
|
| 9 | % |
|
Operating margin (2) |
|
| 299.4 |
|
|
| 300.0 |
|
|
| (0.6 | ) |
|
| — |
|
|
Depreciation and amortization expenses |
|
| 193.5 |
|
|
| 118.6 |
|
|
| 74.9 |
|
|
| 63 | % |
|
General and administrative expenses |
|
| 43.4 |
|
|
| 40.2 |
|
|
| 3.2 |
|
|
| 8 | % |
|
Goodwill impairment |
|
| 24.0 |
|
|
| — |
|
|
| 24.0 |
|
|
| — |
|
|
Other operating (income) expenses |
|
| 1.0 |
|
|
| 0.6 |
|
|
| 0.4 |
|
|
| 67 | % |
|
Income from operations |
|
| 37.5 |
|
|
| 140.6 |
|
|
| (103.1 | ) |
|
| 73 | % |
|
Interest expense, net |
|
| (46.9 | ) |
|
| (50.0 | ) |
|
| 3.1 |
|
|
| 6 | % |
|
Equity earnings (loss) |
|
| (4.8 | ) |
|
| 1.9 |
|
|
| (6.7 | ) |
|
| 353 | % |
|
Gain (loss) from financing activities |
|
| 24.7 |
|
|
| — |
|
|
| 24.7 |
|
|
| 0 | % |
|
Other income (expense) |
|
| (0.1 | ) |
|
| (13.6 | ) |
|
| 13.5 |
|
|
| 99 | % |
|
Income tax (expense) benefit |
|
| 0.2 |
|
|
| (1.1 | ) |
|
| 1.3 |
|
|
| 118 | % |
|
Net income (loss) |
|
| 10.6 |
|
|
| 77.8 |
|
|
| (67.2 | ) |
|
| 86 | % |
|
Less: Net income attributable to noncontrolling interests |
|
| 3.0 |
|
|
| 5.0 |
|
|
| (2.0 | ) |
|
| 40 | % |
|
Net income (loss) attributable to limited and the general partners |
| $ | 7.6 |
|
| $ | 72.8 |
|
| $ | (65.2 | ) |
|
| 90 | % |
|
Financial and operating data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
| 176.9 |
|
|
| 157.3 |
|
|
| 19.6 |
|
|
| 12 | % |
|
Business Acquisitions |
|
| — |
|
|
| 5,024.2 |
|
|
| (5,024.2 | ) |
|
| 100 | % |
|
Operating statistics: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil gathered, MBbl/d |
|
| 108.1 |
|
|
| 101.2 |
|
|
| 6.9 |
|
|
| 7 | % |
|
Plant natural gas inlet, MMcf/d (3)(4)(5) |
|
| 3,405.9 |
|
|
| 2,499.1 |
|
|
| 906.8 |
|
|
| 36 | % |
|
Gross NGL production, MBbl/d (5) |
|
| 284.6 |
|
|
| 193.7 |
|
|
| 90.9 |
|
|
| 47 | % |
|
Export volumes, MBbl/d (6) |
|
| 181.0 |
|
|
| 191.7 |
|
|
| (10.7 | ) |
|
| 6 | % |
|
Natural gas sales, BBtu/d (4)(5)(7) |
|
| 1,974.6 |
|
|
| 1,225.2 |
|
|
| 749.3 |
|
|
| 61 | % |
|
NGL sales, MBbl/d (5)(7) |
|
| 547.8 |
|
|
| 509.6 |
|
|
| 38.2 |
|
|
| 8 | % |
|
Condensate sales, MBbl/d (5) |
|
| 9.5 |
|
|
| 5.8 |
|
|
| 3.7 |
|
|
| 63 | % |
|
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||||||||
2015 | 2014 | 2015 vs. 2014 | 2015 | 2014 | 2015 vs. 2014 | |||||||||||||||||||||||||||
Revenues: | ($ in millions, except operating statistics and price amounts) | |||||||||||||||||||||||||||||||
Sales of commodities | $ | 1,321.3 | $ | 2,009.2 | $ | (687.9 | ) | 34 | % | $ | 4,119.6 | $ | 5,853.3 | $ | (1,733.7 | ) | 30 | % | ||||||||||||||
Fees from midstream services | 310.8 | 279.1 | 31.7 | 11 | % | 891.6 | 730.4 | 161.2 | 22 | % | ||||||||||||||||||||||
Total revenues | 1,632.1 | 2,288.3 | (656.2 | ) | 29 | % | 5,011.2 | 6,583.7 | (1,572.5 | ) | 24 | % | ||||||||||||||||||||
Product purchases | 1,172.4 | 1,880.5 | (708.1 | ) | 38 | % | 3,677.7 | 5,412.2 | (1,734.5 | ) | 32 | % | ||||||||||||||||||||
Gross margin (1) | 459.7 | 407.8 | 51.9 | 13 | % | 1,333.5 | 1,171.5 | 162.0 | 14 | % | ||||||||||||||||||||||
Operating expenses | 133.6 | 112.8 | 20.8 | 18 | % | 381.8 | 323.6 | 58.2 | 18 | % | ||||||||||||||||||||||
Operating margin (2) | 326.1 | 295.0 | 31.1 | 11 | % | 951.7 | 847.9 | 103.8 | 12 | % | ||||||||||||||||||||||
Depreciation and amortization expenses | 165.8 | 87.5 | 78.3 | 89 | % | 448.3 | 252.8 | 195.5 | 77 | % | ||||||||||||||||||||||
General and administrative expenses | 42.9 | 40.4 | 2.5 | 6 | % | 130.1 | 115.3 | 14.8 | 13 | % | ||||||||||||||||||||||
Other operating (income) expenses | 0.1 | (4.3 | ) | 4.4 | 102 | % | 0.6 | (5.3 | ) | 5.9 | 111 | % | ||||||||||||||||||||
Income from operations | 117.3 | 171.4 | (54.1 | ) | 32 | % | 372.7 | 485.1 | (112.4 | ) | 23 | % | ||||||||||||||||||||
Interest expense, net | (64.1 | ) | (36.0 | ) | (28.1 | ) | 78 | % | (177.2 | ) | (104.1 | ) | (73.1 | ) | 70 | % | ||||||||||||||||
Equity earnings | (1.6 | ) | 4.7 | (6.3 | ) | 134 | % | (1.1 | ) | 13.8 | (14.9 | ) | 108 | % | ||||||||||||||||||
Loss from financing activities | (0.5 | ) | - | (0.5 | ) | NM | (0.5 | ) | - | (0.5 | ) | NM | ||||||||||||||||||||
Other income (expense) | 1.8 | (0.6 | ) | 2.4 | NM | (9.1 | ) | (0.6 | ) | (8.5 | ) | NM | ||||||||||||||||||||
Income tax (expense) benefit | 0.4 | (1.3 | ) | 1.7 | 131 | % | (0.4 | ) | (3.7 | ) | 3.3 | 89 | % | |||||||||||||||||||
Net income | 53.3 | 138.2 | (84.9 | ) | 61 | % | 184.4 | 390.5 | (206.1 | ) | 53 | % | ||||||||||||||||||||
Less: Net income attributable to noncontrolling interests | 4.8 | 9.9 | (5.1 | ) | 52 | % | 17.3 | 30.9 | (13.6 | ) | 44 | % | ||||||||||||||||||||
Net income attributable to Targa Resources Partners LP | $ | 48.5 | $ | 128.3 | $ | (79.8 | ) | 62 | % | $ | 167.1 | $ | 359.6 | $ | (192.5 | ) | 54 | % | ||||||||||||||
Financial and operating data: | ||||||||||||||||||||||||||||||||
Financial data: | ||||||||||||||||||||||||||||||||
Adjusted EBITDA (3) | $ | 305.8 | $ | 248.8 | $ | 57.0 | 23 | % | $ | 866.5 | $ | 712.1 | $ | 154.4 | 22 | % | ||||||||||||||||
Distributable cash flow (4) | 220.7 | 194.6 | 26.1 | 13 | % | 630.8 | 564.0 | 66.8 | 12 | % | ||||||||||||||||||||||
Capital expenditures | 186.2 | 142.9 | 43.3 | 30 | % | 571.0 | 533.8 | 37.2 | 7 | % | ||||||||||||||||||||||
Operating statistics: | ||||||||||||||||||||||||||||||||
Crude oil gathered, MBbl/d | 108.9 | 99.2 | 9.7 | 10 | % | 105.4 | 86.0 | 19.4 | 23 | % | ||||||||||||||||||||||
Plant natural gas inlet, MMcf/d (5)(6)(7) | 3,452.5 | 2,170.3 | 1,282.2 | 59 | % | 3,163.2 | 2,111.2 | 1,052.0 | 50 | % | ||||||||||||||||||||||
Gross NGL production, MBbl/d (7) | 283.4 | 157.6 | 125.8 | 80 | % | 255.7 | 152.2 | 103.5 | 68 | % | ||||||||||||||||||||||
Export volumes, MBbl/d (8) | 184.1 | 205.9 | (21.8 | ) | 11 | % | 180.0 | 160.5 | 19.5 | 12 | % | |||||||||||||||||||||
Natural gas sales, BBtu/d (6)(7) | 1,932.3 | 923.7 | 1,008.6 | 109 | % | 1,721.4 | 890.5 | 830.9 | 93 | % | ||||||||||||||||||||||
NGL sales, MBbl/d (7) | 499.2 | 441.6 | 57.6 | 13 | % | 501.2 | 401.6 | 99.6 | 25 | % | ||||||||||||||||||||||
Condensate sales, MBbl/d (7) | 10.8 | 4.8 | 6.0 | 125 | % | 9.5 | 4.4 | 5.1 | 116 | % |
(1) | Gross margin is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations.” |
(2) | Operating margin is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations.” |
(3) |
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. |
(4) | Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes. |
(5) | These volume statistics are presented with the numerator as the total volume sold during the quarter and the denominator as the number of calendar days during the quarter. |
(6) | 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. |
(7) | Includes the impact of intersegment eliminations. |
42
Three Months Ended September 30, 2015March 31, 2016 Compared to Three Months Ended September 30, 2014
The decrease in revenues was primarily due to significantly lower commodity prices ($1,749.6522.2 million) exceededpartially offset by the favorable impacts of inclusion of a full quartertwo additional months of operations of TPL during 2016 ($388.2 million), other volume increases ($648.3 million), and favorable hedge settlements ($21.8270.1 million). Fee-based and other revenues increaseddecreased slightly due to lower fractionation and export fees offset by the inclusionadditional impact of an additional two months of TPL’s fee revenue in 2016 ($55.040.9 million), which were partially offset by lower export fees.
Lower commodity revenues wasprices brought a commensurate reduction in product purchases due to significantly lower commodity costs ($1,050.9 million), which wereprices, partially offset by the inclusion of product purchases related to TPL’stwo additional months of operations from TPL in 2016 ($342.8137.5 million).
The higher gross margin in 20152016 was attributable to the inclusion of TPL operations, increased throughput related to other system expansions in our Field Gathering and Processing segment, recognition of a renegotiated commercial contract and increased terminaling and storage fees, partially offset by lower fractionation and export margina decrease in our Logistics and Marketing segments.segment due to lower fractionation margin, fees in 2015 from renegotiated commercial arrangements related to our crude and condensate splitter project, lower LPG export margin, and lower terminaling and storage throughput. Higher operating expenses are due to the inclusion of TPL’s operations ($29.4 million), which more thanfor a full quarter in 2016, partially offset by to the cost savings generated throughout our other operating areas. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in gross margin and operating margin on a segment basis.
The increase in depreciation and amortization expenses primarily reflects the impact of TPL the planned increased amortization of the Badlands intangible assetsoperations and growth investments placed in service after June 2014, including the international export expansion project, continuing development at Badlands andfrom other system expansions.
Higher general and administrative expenses is due toin 2016 reflect the impact of the inclusion of TPL general and administrative costs ($8.4 million), which was partially offset by general and administrative savings ($5.9 million), primarily from lower compensation and related costs.
During 2016, we recognized an additional impairment of goodwill of $24.0 million to finalize the $290 million provisional impairment recorded during the fourth quarter of 2015.
The increasedecrease in net interest expense primarily reflects higher borrowings attributable to$18.5 million of non-cash interest income from the APL merger and lower capitalized interest associated with major capital projects compared to 2014.
Other expense in 2015 was primarily attributable to increased Field Gathering and Processing throughput volumes primarily associated with the inclusion of TPL’s operations and the recognition of a renegotiated commercial contract, partially offset by lower export margins and treating and reservation fees in our Logistics and Marketing segments. Higher operating expenses are duenon-recurring transaction costs relate to the inclusionAtlas mergers.
During 2016, we recognized a gain of TPL’s operations ($69.4 million), which more than offset the cost savings generated throughout our$24.7 million on open market debt repurchases and other operating areas. See “—Results of Operations—By Reportable Segment” for additional information regarding changesfinancing activities.
The decrease in gross margin and operating margin on a segment basis.
Results of Operations—By Reportable Segment
Our operating margins by reportable segment are:
|
| Gathering and Processing |
|
| Logistics and Marketing |
|
| Other |
|
| Corporate and Eliminations |
|
| Total |
| |||||
| (In millions) |
| ||||||||||||||||||
Three Months Ended: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
March 31, 2016 |
| $ | 115.6 |
|
| $ | 157.0 |
|
| $ | 26.8 |
|
| $ | - |
|
| $ | 299.4 |
|
March 31, 2015 |
|
| 87.0 |
|
|
| 191.3 |
|
|
| 21.7 |
|
|
| - |
|
|
| 300.0 |
|
Field Gathering and Processing | Coastal Gathering and Processing | Logistics Assets | Marketing and Distribution | Other | Total | |||||||||||||||||||
(In millions) | ||||||||||||||||||||||||
Three Months Ended: | ||||||||||||||||||||||||
September 30, 2015 | $ | 132.6 | $ | 7.9 | $ | 103.6 | $ | 60.2 | $ | 21.8 | $ | 326.1 | ||||||||||||
September 30, 2014 | 98.0 | 19.1 | 118.6 | 61.6 | (2.3 | ) | 295.0 | |||||||||||||||||
Nine Months Ended: | ||||||||||||||||||||||||
September 30, 2015 | $ | 349.9 | $ | 22.1 | $ | 341.7 | $ | 177.3 | $ | 60.7 | $ | 951.7 | ||||||||||||
September 30, 2014 | 289.8 | 67.0 | 324.0 | 179.5 | (12.4 | ) | 847.9 |
Gathering and Processing SegmentsSegment
| Three Months Ended March 31, |
|
|
|
|
|
|
|
|
|
| |||||||
| 2016 |
|
| 2015 |
|
| 2016 vs. 2015 |
| ||||||||||
Gross margin | $ |
| 194.1 |
|
| $ |
| 152.6 |
|
| $ |
| 41.5 |
|
|
| 27 | % |
Operating expenses |
|
| 78.5 |
|
|
|
| 65.6 |
|
|
|
| 12.9 |
|
|
| 20 | % |
Operating margin | $ |
| 115.6 |
|
| $ |
| 87.0 |
|
| $ |
| 28.6 |
|
|
| 33 | % |
Operating statistics (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet, MMcf/d (2),(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SAOU (4) |
|
| 243.5 |
|
|
|
| 216.5 |
|
|
|
| 27.0 |
|
|
| 12 | % |
WestTX (5) |
|
| 461.0 |
|
|
|
| 136.2 |
|
|
|
| 324.8 |
|
|
| 238 | % |
Sand Hills (4) |
|
| 151.1 |
|
|
|
| 158.5 |
|
|
|
| (7.4 | ) |
|
| 5 | % |
Versado |
|
| 180.0 |
|
|
|
| 173.3 |
|
|
|
| 6.7 |
|
|
| 4 | % |
Permian |
|
| 1,035.6 |
|
|
|
| 684.5 |
|
|
|
| 351.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (5) |
|
| 175.7 |
|
|
|
| 48.6 |
|
|
|
| 127.1 |
|
|
| 262 | % |
North Texas |
|
| 327.5 |
|
|
|
| 360.0 |
|
|
|
| (32.5 | ) |
|
| 9 | % |
SouthOK (5) |
|
| 457.9 |
|
|
|
| 170.2 |
|
|
|
| 287.7 |
|
|
| 169 | % |
WestOK (5) |
|
| 487.0 |
|
|
|
| 211.2 |
|
|
|
| 275.8 |
|
|
| 131 | % |
Central |
|
| 1,448.1 |
|
|
|
| 790.0 |
|
|
|
| 658.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (6) |
|
| 53.7 |
|
|
|
| 42.1 |
|
|
|
| 11.6 |
|
|
| 28 | % |
Total Field |
|
| 2,537.4 |
|
|
|
| 1,516.6 |
|
|
|
| 1,020.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
| 868.6 |
|
|
|
| 982.4 |
|
|
|
| (113.8 | ) |
|
| 12 | % |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
| 3,406.0 |
|
|
|
| 2,499.0 |
|
|
|
| 907.0 |
|
|
| 36 | % |
Gross NGL production, MBbl/d (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SAOU (4) |
|
| 29.2 |
|
|
|
| 25.3 |
|
|
|
| 3.9 |
|
|
| 15 | % |
WestTX (5) |
|
| 52.4 |
|
|
|
| 15.8 |
|
|
|
| 36.6 |
|
|
| 232 | % |
Sand Hills (4) |
|
| 15.7 |
|
|
|
| 17.0 |
|
|
|
| (1.3 | ) |
|
| 8 | % |
Versado |
|
| 21.9 |
|
|
|
| 22.5 |
|
|
|
| (0.6 | ) |
|
| 3 | % |
Permian |
|
| 119.2 |
|
|
|
| 80.6 |
|
|
|
| 38.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (5) |
|
| 23.1 |
|
|
|
| 6.1 |
|
|
|
| 17.0 |
|
|
| 279 | % |
North Texas |
|
| 35.7 |
|
|
|
| 40.6 |
|
|
|
| (4.9 | ) |
|
| 12 | % |
SouthOK (5) |
|
| 28.0 |
|
|
|
| 9.9 |
|
|
|
| 18.1 |
|
|
| 183 | % |
WestOK (5) |
|
| 26.9 |
|
|
|
| 10.2 |
|
|
|
| 16.7 |
|
|
| 164 | % |
Central |
|
| 113.7 |
|
|
|
| 66.8 |
|
|
|
| 46.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands |
|
| 7.6 |
|
|
|
| 3.9 |
|
|
|
| 3.7 |
|
|
| 95 | % |
Total Field |
|
| 240.5 |
|
|
|
| 151.3 |
|
|
|
| 89.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
| 44.2 |
|
|
|
| 42.4 |
|
|
|
| 1.8 |
|
|
| 4 | % |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
| 284.7 |
|
|
|
| 193.7 |
|
|
|
| 91.0 |
|
|
| 47 | % |
Crude oil gathered, MBbl/d |
|
| 108.1 |
|
|
|
| 101.2 |
|
|
|
| 6.9 |
|
|
| 7 | % |
Natural gas sales, BBtu/d (3) |
|
| 1,687.2 |
|
|
|
| 1,083.3 |
|
|
|
| 604.0 |
|
|
| 56 | % |
NGL sales, MBbl/d |
|
| 219.3 |
|
|
|
| 150.5 |
|
|
|
| 68.8 |
|
|
| 46 | % |
Condensate sales, MBbl/d |
|
| 9.5 |
|
|
|
| 5.7 |
|
|
|
| 3.8 |
|
|
| 67 | % |
Average realized prices (7): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, $/MMBtu |
|
| 1.75 |
|
|
|
| 2.65 |
|
|
|
| (0.90 | ) |
|
| 34 | % |
NGL, $/gal |
|
| 0.28 |
|
|
|
| 0.39 |
|
|
|
| (0.11 | ) |
|
| 29 | % |
Condensate, $/Bbl |
|
| 25.65 |
|
|
|
| 40.70 |
|
|
|
| (15.05 | ) |
|
| 37 | % |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||||||||
2015 | 2014 | 2015 vs. 2014 | 2015 | 2014 | 2015 vs. 2014 | |||||||||||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||||||||||
Gross margin | $ | 206.3 | $ | 145.6 | $ | 60.7 | 42 | % | $ | 556.4 | $ | 428.7 | $ | 127.7 | 30 | % | ||||||||||||||||
Operating expenses | 73.7 | 47.6 | 26.1 | 55 | % | 206.5 | 138.9 | 67.6 | 49 | % | ||||||||||||||||||||||
Operating margin | $ | 132.6 | $ | 98.0 | $ | 34.6 | 35 | % | $ | 349.9 | $ | 289.8 | $ | 60.1 | 21 | % | ||||||||||||||||
Operating statistics (1): | ||||||||||||||||||||||||||||||||
Plant natural gas inlet, MMcf/d (2),(3) | ||||||||||||||||||||||||||||||||
SAOU (4) | 240.2 | 207.0 | 33.2 | 16 | % | 231.6 | 183.4 | 48.2 | 26 | % | ||||||||||||||||||||||
WestTX (5) | 460.2 | - | 460.2 | NM | 344.4 | - | 344.4 | NM | ||||||||||||||||||||||||
Sand Hills | 168.1 | 166.7 | 1.4 | 1 | % | 166.1 | 164.4 | 1.7 | 1 | % | ||||||||||||||||||||||
Versado | 187.8 | 172.2 | 15.6 | 9 | % | 182.3 | 165.9 | 16.4 | 10 | % | ||||||||||||||||||||||
SouthTX (5) | 139.1 | - | 139.1 | NM | 112.9 | - | 112.9 | NM | ||||||||||||||||||||||||
North Texas (6) | 339.1 | 361.8 | (22.7 | ) | 6 | % | 351.7 | 350.3 | 1.4 | 0 | % | |||||||||||||||||||||
SouthOK (5) | 473.8 | - | 473.8 | NM | 378.2 | - | 378.2 | NM | ||||||||||||||||||||||||
WestOK (5) | 563.4 | - | 563.4 | NM | 458.6 | - | 458.6 | NM | ||||||||||||||||||||||||
Badlands (7) | 50.7 | 44.9 | 5.8 | 13 | % | 46.6 | 39.2 | 7.4 | 19 | % | ||||||||||||||||||||||
2,622.4 | 952.6 | 1,669.8 | 175 | % | 2,272.4 | 903.2 | 1,369.2 | 152 | % | |||||||||||||||||||||||
Gross NGL production, MBbl/d (3) | ||||||||||||||||||||||||||||||||
SAOU | 28.6 | 25.9 | 2.7 | 10 | % | 27.2 | 25.1 | 2.1 | 8 | % | ||||||||||||||||||||||
WestTX (5) | 53.6 | - | 53.6 | NM | 40.1 | - | 40.1 | NM | ||||||||||||||||||||||||
Sand Hills | 17.5 | 17.6 | (0.1 | ) | 1 | % | 17.6 | 18.1 | (0.5 | ) | 3 | % | ||||||||||||||||||||
Versado | 24.0 | 22.0 | 2.0 | 9 | % | 23.5 | 20.8 | 2.7 | 13 | % | ||||||||||||||||||||||
SouthTX (5) | 13.7 | - | 13.7 | NM | 13.2 | - | 13.2 | NM | ||||||||||||||||||||||||
North Texas | 39.0 | 39.7 | (0.7 | ) | 2 | % | 40.2 | 36.9 | 3.3 | 9 | % | |||||||||||||||||||||
SouthOK (5) | 30.3 | - | 30.3 | NM | 23.4 | - | 23.4 | NM | ||||||||||||||||||||||||
WestOK (5) | 27.9 | - | 27.9 | NM | 22.9 | - | 22.9 | NM | ||||||||||||||||||||||||
Badlands | 7.4 | 4.0 | 3.4 | 85 | % | 6.3 | 3.5 | 2.8 | 80 | % | ||||||||||||||||||||||
242.0 | 109.2 | 132.8 | 122 | % | 214.4 | 104.4 | 110.0 | 105 | % | |||||||||||||||||||||||
Crude oil gathered, MBbl/d | 108.9 | 99.2 | 9.7 | 10 | % | 105.4 | 86.0 | 19.4 | 23 | % | ||||||||||||||||||||||
Natural gas sales, BBtu/d (3) | 1,518.6 | 478.7 | 1,039.9 | 217 | % | 1,308.7 | 453.4 | 855.3 | 189 | % | ||||||||||||||||||||||
NGL sales, MBbl/d | 191.1 | 82.4 | 108.7 | 132 | % | 167.2 | 79.5 | 87.7 | 110 | % | ||||||||||||||||||||||
Condensate sales, MBbl/d | 9.8 | 3.9 | 5.9 | 152 | % | 8.5 | 3.6 | 4.9 | 136 | % | ||||||||||||||||||||||
Average realized prices (8): | ||||||||||||||||||||||||||||||||
Natural gas, $/MMBtu | 2.48 | 3.80 | (1.32 | ) | 35 | % | 2.43 | 4.21 | (1.78 | ) | 42 | % | ||||||||||||||||||||
NGL, $/gal | 0.31 | 0.75 | (0.44 | ) | 58 | % | 0.35 | 0.79 | (0.44 | ) | 55 | % | ||||||||||||||||||||
Condensate, $/Bbl | 39.96 | 85.08 | (45.12 | ) | 53 | % | 43.31 | 88.17 | (44.86 | ) | 51 | % |
(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 quarter and the denominator is the number of calendar days during the quarter, including the volumes related to plants acquired in the APL merger. |
(2) | Plant natural gas inlet represents our 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 |
(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 September 30, 2015March 31, 2016 Compared to Three Months Ended September 30, 2014
The increase in gross margin was primarily due to the inclusion of the TPL volumes along with other volume increasesfor a full quarter of 2016 partially offset by significantly lower commodity sales prices.prices and slightly lower throughput volumes on our other systems. The plant inlet volume increases in plant inlet volumesthe Permian region attributable to SAOU, Sand Hills (see footnote (4) above) and Versado were driven by system expansions and by increased producer activity which increased available supply across most of our areas of operation partially offset by reduced producer activity in North Texas. Higher natural gas and NGL sales reflect similar factors. Badlands crude oil and natural gas volumes increased significantly due to increased producer activity. The Little Missouri 3 plant which started commercial operations in January 2015 was a benefit to the gas volumes in the third quarter of 2015.
Excluding the impact of adding operating expenses for TPL and system expansions, operating expenses for most areas higher operating expenses were primarily driven by the inclusion of TPL operating expenses and increased expenses associated with the commencement in operations of the Longhorn, High Plains and Little Missouri 3 plants.
The table below provides a reconciliation between gross operating statistics and the actual reported operating statistics for the Field Gathering and Processing segment:
|
| Three Months Ended March 31, 2016 |
| |||||||||||||
Operating statistics: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet, MMcf/d (1),(2) |
| Gross Volume (3) |
|
| Ownership % |
|
| Net Volume (3) |
|
| Actual Reported |
| ||||
SAOU (4) |
|
| 243.5 |
|
|
| 100 | % |
|
| 243.5 |
|
|
| 243.5 |
|
WestTX (5)(6) |
|
| 633.2 |
|
|
| 73 | % |
|
| 461.0 |
|
|
| 461.0 |
|
Sand Hills (4) |
|
| 151.1 |
|
|
| 100 | % |
|
| 151.1 |
|
|
| 151.1 |
|
Versado (7) |
|
| 180.0 |
|
|
| 63 | % |
|
| 113.4 |
|
|
| 180.0 |
|
Permian |
|
| 1,207.8 |
|
|
|
|
|
|
| 969.0 |
|
|
| 1,035.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (5) |
|
| 175.7 |
|
|
| 100 | % |
|
| 175.7 |
|
|
| 175.7 |
|
North Texas |
|
| 327.5 |
|
|
| 100 | % |
|
| 327.5 |
|
|
| 327.5 |
|
SouthOK (5) |
|
| 457.9 |
|
| Varies (8) |
|
|
| 380.9 |
|
|
| 457.9 |
| |
WestOK (5) |
|
| 487.0 |
|
|
| 100 | % |
|
| 487.0 |
|
|
| 487.0 |
|
Central |
|
| 1,448.1 |
|
|
|
|
|
|
| 1,371.1 |
|
|
| 1,448.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (9) |
|
| 53.7 |
|
|
| 100 | % |
|
| 53.7 |
|
|
| 53.7 |
|
Total Field |
|
| 2,709.6 |
|
|
|
|
|
|
| 2,393.8 |
|
|
| 2,537.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross NGL production, MBbl/d (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SAOU (4) |
|
| 29.2 |
|
|
| 100 | % |
|
| 29.2 |
|
|
| 29.2 |
|
WestTX (5)(6) |
|
| 72.0 |
|
|
| 73 | % |
|
| 52.4 |
|
|
| 52.4 |
|
Sand Hills (4) |
|
| 15.7 |
|
|
| 100 | % |
|
| 15.7 |
|
|
| 15.7 |
|
Versado (7) |
|
| 21.9 |
|
|
| 63 | % |
|
| 13.8 |
|
|
| 21.9 |
|
Permian |
|
| 138.8 |
|
|
|
|
|
|
| 111.1 |
|
|
| 119.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (5) |
|
| 23.1 |
|
|
| 100 | % |
|
| 23.1 |
|
|
| 23.1 |
|
North Texas |
|
| 35.7 |
|
|
| 100 | % |
|
| 35.7 |
|
|
| 35.7 |
|
SouthOK (5) |
|
| 28.0 |
|
| Varies (8) |
|
|
| 24.7 |
|
|
| 28.0 |
| |
WestOK (5) |
|
| 26.9 |
|
|
| 100 | % |
|
| 26.9 |
|
|
| 26.9 |
|
Central |
|
| 113.7 |
|
|
|
|
|
|
| 110.4 |
|
|
| 113.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands |
|
| 7.6 |
|
|
| 100 | % |
|
| 7.6 |
|
|
| 7.6 |
|
Total Field |
|
| 260.1 |
|
|
|
|
|
|
| 229.1 |
|
|
| 240.5 |
|
Three Months Ended September 30, 2015 | ||||||||||||||||
Operating statistics: | ||||||||||||||||
Plant natural gas inlet, MMcf/d (1),(2) | Gross Volume (3) | Ownership % | Net Volume (3) | Actual Reported | ||||||||||||
SAOU | 240.2 | 100.0 | % | 240.2 | 240.2 | |||||||||||
WestTX (4)(5) | 632.1 | 72.8 | % | 460.2 | 460.2 | |||||||||||
Sand Hills | 168.1 | 100.0 | % | 168.1 | 168.1 | |||||||||||
Versado (6) | 187.8 | 63.0 | % | 118.3 | 187.8 | |||||||||||
SouthTX (4) | 139.1 | 100.0 | % | 139.1 | 139.1 | |||||||||||
North Texas | 339.1 | 100.0 | % | 339.1 | 339.1 | |||||||||||
SouthOK (4) | 473.8 | Varies (7) | 397.1 | 473.8 | ||||||||||||
WestOK (4) | 563.4 | 100.0 | % | 563.4 | 563.4 | |||||||||||
Badlands (8) | 50.7 | 100.0 | % | 50.7 | 50.7 | |||||||||||
Total | 2,794.3 | 2,476.2 | 2,622.4 | |||||||||||||
Gross NGL production, MBbl/d (2) | ||||||||||||||||
SAOU | 28.6 | 100.0 | % | 28.6 | 28.6 | |||||||||||
WestTX (4)(5) | 73.6 | 72.8 | % | 53.6 | 53.6 | |||||||||||
Sand Hills | 17.5 | 100.0 | % | 17.5 | 17.5 | |||||||||||
Versado | 24.0 | 63.0 | % | 15.1 | 24.0 | |||||||||||
SouthTX (4) | 13.7 | 100.0 | % | 13.7 | 13.7 | |||||||||||
North Texas | 39.0 | 100.0 | % | 39.0 | 39.0 | |||||||||||
SouthOK (4) | 30.3 | Varies (7) | 27.0 | 30.3 | ||||||||||||
WestOK (4) | 27.9 | 100.0 | % | 27.9 | 27.9 | |||||||||||
Badlands | 7.4 | 100.0 | % | 7.4 | 7.4 | |||||||||||
Total | 262.0 | 229.8 | 242.0 |
(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 quarter and the denominator is the number of calendar days during the quarter. |
(4) | Includes wellhead gathered volumes moved from Sand Hills to SAOU for processing. |
(5) | Operations acquired as part of the APL merger effective February 27, 2015. |
(6) | Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials. |
(7) | Versado is a consolidated subsidiary and its financial results are presented on a gross basis in TRC’s reported financials. |
46
(9) | Badlands natural gas inlet represents the total wellhead gathered volume. |
|
| Three Months Ended March 31, 2015 |
| |||||||||||||||||||||||
Operating statistics: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet, MMcf/d (1),(2) |
| Gross Volume (3) |
|
| Ownership % |
|
| Net Volume (3) |
|
|
| Pro Forma (4) |
|
|
| Timing Adjustment (5) |
|
| Actual Reported |
| ||||||
SAOU (6) |
|
| 216.5 |
|
|
| 100 | % |
|
| 216.5 |
|
|
|
| 216.5 |
|
|
|
| - |
|
|
| 216.5 |
|
WestTX (7)(8) |
|
| 543.3 |
|
|
| 73 | % |
|
| 395.5 |
|
|
|
| 395.5 |
|
|
|
| (259.3 | ) |
|
| 136.2 |
|
Sand Hills (6) |
|
| 158.5 |
|
|
| 100 | % |
|
| 158.5 |
|
|
|
| 158.5 |
|
|
|
| - |
|
|
| 158.5 |
|
Versado (9) |
|
| 173.3 |
|
|
| 63 | % |
|
| 109.2 |
|
|
|
| 173.3 |
|
|
|
| - |
|
|
| 173.3 |
|
Permian |
|
| 1,091.6 |
|
|
|
|
|
|
| 879.7 |
|
|
|
| 943.8 |
|
|
|
| (259.3 | ) |
|
| 684.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (7) |
|
| 141.1 |
|
|
| 100 | % |
|
| 141.1 |
|
|
|
| 141.1 |
|
|
|
| (92.5 | ) |
|
| 48.6 |
|
North Texas |
|
| 360.0 |
|
|
| 100 | % |
|
| 360.0 |
|
|
|
| 360.0 |
|
|
|
| - |
|
|
| 360.0 |
|
SouthOK (7) |
|
| 494.1 |
|
| Varies (10) |
|
|
| 415.0 |
|
|
|
| 494.1 |
|
|
|
| (323.9 | ) |
|
| 170.2 |
| |
WestOK (7) |
|
| 613.2 |
|
|
| 100 | % |
|
| 613.2 |
|
|
|
| 613.2 |
|
|
|
| (402.0 | ) |
|
| 211.2 |
|
Central |
|
| 1,608.4 |
|
|
|
|
|
|
| 1,529.3 |
|
|
|
| 1,608.4 |
|
|
|
| (818.4 | ) |
|
| 790.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (11) |
|
| 42.1 |
|
|
| 100 | % |
|
| 42.1 |
|
|
|
| 42.1 |
|
|
|
| - |
|
|
| 42.1 |
|
Total Field |
|
| 2,742.1 |
|
|
|
|
|
|
| 2,451.1 |
|
|
|
| 2,594.3 |
|
|
|
| (1,077.7 | ) |
|
| 1,516.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross NGL production, MBbl/d (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SAOU (6) |
|
| 25.3 |
|
|
| 100 | % |
|
| 25.3 |
|
|
|
| 25.3 |
|
|
|
| - |
|
|
| 25.3 |
|
WestTX (7)(8) |
|
| 63.0 |
|
|
| 73 | % |
|
| 45.9 |
|
|
|
| 45.9 |
|
|
|
| (30.1 | ) |
|
| 15.8 |
|
Sand Hills (6) |
|
| 17.0 |
|
|
| 100 | % |
|
| 17.0 |
|
|
|
| 17.0 |
|
|
|
| - |
|
|
| 17.0 |
|
Versado (9) |
|
| 22.5 |
|
|
| 63 | % |
|
| 14.2 |
|
|
|
| 22.5 |
|
|
|
| - |
|
|
| 22.5 |
|
Permian |
|
| 127.8 |
|
|
|
|
|
|
| 102.3 |
|
|
|
| 110.7 |
|
|
|
| (30.1 | ) |
|
| 80.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (7) |
|
| 17.7 |
|
|
| 100 | % |
|
| 17.7 |
|
|
|
| 17.7 |
|
|
|
| (11.6 | ) |
|
| 6.1 |
|
North Texas |
|
| 40.6 |
|
|
| 100 | % |
|
| 40.6 |
|
|
|
| 40.6 |
|
|
|
| - |
|
|
| 40.6 |
|
SouthOK (7) |
|
| 28.7 |
|
| Varies (10) |
|
|
| 25.3 |
|
|
|
| 28.7 |
|
|
|
| (18.8 | ) |
|
| 9.9 |
| |
WestOK (7) |
|
| 29.6 |
|
|
| 100 | % |
|
| 29.6 |
|
|
|
| 29.6 |
|
|
|
| (19.4 | ) |
|
| 10.2 |
|
Central |
|
| 116.6 |
|
|
|
|
|
|
| 113.2 |
|
|
|
| 116.6 |
|
|
|
| (49.8 | ) |
|
| 66.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands |
|
| 3.9 |
|
|
| 100 | % |
|
| 3.9 |
|
|
|
| 3.9 |
|
|
|
| - |
|
|
| 3.9 |
|
Total Field |
|
| 248.3 |
|
|
|
|
|
|
| 219.5 |
|
|
|
| 231.2 |
|
|
|
| (79.9 | ) |
|
| 151.3 |
|
(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, while natural gas sales exclude producer take-in-kind volumes. |
(3) | For these volume statistics presented, the numerator is the total volume sold during the |
(4) | Pro forma statistics represents volumes per day while owned by us. |
(5) | Timing adjustment made to the pro forma statistics to adjust for the actual reported statistics based on the full period. |
(6) | Includes wellhead gathered volumes moved from Sand Hills to SAOU for processing |
(7) | Operations acquired as part of the APL merger effective February 27, 2015. |
(8) | Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials. |
(9) | Versado is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials. |
(10) | 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 our reported financials. |
(11) | Badlands natural gas inlet represents the total wellhead gathered volume. |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||||||||
2015 | 2014 | 2015 vs. 2014 | 2015 | 2014 | 2015 vs. 2014 | |||||||||||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||||||||||
Gross margin | $ | 17.7 | $ | 32.3 | $ | (14.6 | ) | 45 | % | $ | 52.6 | $ | 102.2 | $ | (49.6 | ) | 49 | % | ||||||||||||||
Operating expenses | 9.8 | 13.2 | (3.4 | ) | 26 | % | 30.5 | 35.2 | (4.7 | ) | 13 | % | ||||||||||||||||||||
Operating margin | $ | 7.9 | $ | 19.1 | $ | (11.2 | ) | 59 | % | $ | 22.1 | $ | 67.0 | $ | (44.9 | ) | 67 | % | ||||||||||||||
Operating statistics (1): | ||||||||||||||||||||||||||||||||
Plant natural gas inlet, MMcf/d (2),(3) | ||||||||||||||||||||||||||||||||
LOU | 177.0 | 293.1 | (116.1 | ) | 40 | % | 173.8 | 308.4 | (134.6 | ) | 44 | % | ||||||||||||||||||||
VESCO | 459.3 | 533.9 | (74.6 | ) | 14 | % | 438.9 | 514.9 | (76.0 | ) | 15 | % | ||||||||||||||||||||
Other Coastal Straddles | 193.8 | 390.9 | (197.1 | ) | 50 | % | 278.2 | 384.7 | (106.5 | ) | 28 | % | ||||||||||||||||||||
830.1 | 1,217.9 | (387.8 | ) | 32 | % | 890.9 | 1,208.0 | (317.1 | ) | 26 | % | |||||||||||||||||||||
Gross NGL production, MBbl/d (3) | ||||||||||||||||||||||||||||||||
LOU | 7.1 | 9.2 | (2.1 | ) | 23 | % | 6.7 | 9.6 | (2.9 | ) | 30 | % | ||||||||||||||||||||
VESCO | 27.8 | 27.3 | 0.5 | 2 | % | 25.7 | 26.3 | (0.6 | ) | 2 | % | |||||||||||||||||||||
Other Coastal Straddles | 6.5 | 11.9 | (5.4 | ) | 45 | % | 8.7 | 11.9 | (3.2 | ) | 27 | % | ||||||||||||||||||||
41.4 | 48.4 | (7.0 | ) | 14 | % | 41.1 | 47.8 | (6.7 | ) | 14 | % | |||||||||||||||||||||
Natural gas sales, BBtu/d (3) | 227.6 | 252.7 | (25.1 | ) | 10 | % | 231.4 | 266.5 | (35.1 | ) | 13 | % | ||||||||||||||||||||
NGL sales, MBbl/d | 31.4 | 40.8 | (9.4 | ) | 23 | % | 31.0 | 41.5 | (10.5 | ) | 25 | % | ||||||||||||||||||||
Condensate sales, MBbl/d | 0.8 | 0.7 | 0.1 | 14 | % | 0.8 | 0.7 | 0.1 | 14 | % | ||||||||||||||||||||||
Average realized prices: | ||||||||||||||||||||||||||||||||
Natural gas, $/MMBtu | 2.82 | 4.04 | (1.22 | ) | 30 | % | 2.85 | 4.58 | (1.73 | ) | 38 | % | ||||||||||||||||||||
NGL, $/gal | 0.38 | 0.80 | (0.42 | ) | 53 | % | 0.40 | 0.86 | (0.46 | ) | 53 | % | ||||||||||||||||||||
Condensate, $/Bbl | 49.13 | 102.88 | (53.75 | ) | 52 | % | 51.72 | 100.04 | (48.32 | ) | 48 | % |
|
| Three Months Ended March 31, |
|
|
|
|
|
|
|
|
|
| |||||||
|
| 2016 |
|
| 2015 |
|
| 2016 vs. 2015 |
| ||||||||||
| ($ in millions) |
| |||||||||||||||||
Gross margin |
| $ |
| 210.6 |
|
| $ |
| 246.8 |
|
| $ |
| (36.2 | ) |
|
| 15 | % |
Operating expenses |
|
|
| 53.6 |
|
|
|
| 55.5 |
|
|
|
| (1.9 | ) |
|
| 3 | % |
Operating margin |
| $ |
| 157.0 |
|
| $ |
| 191.3 |
|
| $ |
| (34.3 | ) |
|
| 18 | % |
Operating statistics MBbl/d (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fractionation volumes (2)(3) |
|
|
| 295.5 |
|
|
|
| 340.6 |
|
|
|
| (45.1 | ) |
|
| 13 | % |
LSNG treating volumes (2) |
|
|
| 21.0 |
|
|
|
| 19.4 |
|
|
|
| 1.6 |
|
|
| 8 | % |
Benzene treating volumes (2) |
|
|
| 21.0 |
|
|
|
| 19.4 |
|
|
|
| 1.6 |
|
|
| 8 | % |
Export volumes, MBbl/d (4) |
|
|
| 181.0 |
|
|
|
| 191.7 |
|
|
|
| (10.7 | ) |
|
| 6 | % |
NGL sales, MBbl/d |
|
|
| 482.0 |
|
|
|
| 469.6 |
|
|
|
| 12.3 |
|
|
| 3 | % |
Average realized prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL realized price, $/gal |
| $ |
| 0.41 |
|
| $ |
| 0.54 |
|
| $ |
| (0.13 | ) |
|
| 25 | % |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||||||||
2015 | 2014 | 2015 vs. 2014 | 2015 | 2014 | 2015 vs. 2014 | |||||||||||||||||||||||||||
($ in millions, except operating statistics) | ||||||||||||||||||||||||||||||||
Gross margin (1) | $ | 153.1 | $ | 164.4 | $ | (11.3 | ) | 7 | % | $ | 474.6 | $ | 449.1 | $ | 25.5 | 6 | % | |||||||||||||||
Operating expenses (1) | 49.5 | 45.8 | 3.7 | 8 | % | 132.9 | 125.1 | 7.8 | 6 | % | ||||||||||||||||||||||
Operating margin | $ | 103.6 | $ | 118.6 | $ | (15.0 | ) | 13 | % | $ | 341.7 | $ | 324.0 | $ | 17.7 | 5 | % | |||||||||||||||
Operating statistics MBbl/d(2): | ||||||||||||||||||||||||||||||||
Fractionation volumes (3) | 344.6 | 368.6 | (24.0 | ) | 7 | % | 347.7 | 342.7 | 5.0 | 1 | % | |||||||||||||||||||||
LSNG treating volumes | 23.8 | 24.8 | (1.0 | ) | 4 | % | 22.8 | 24.2 | (1.4 | ) | 6 | % | ||||||||||||||||||||
Benzene treating volumes | 23.8 | 24.8 | (1.0 | ) | 4 | % | 22.8 | 24.2 | (1.4 | ) | 6 | % |
(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 |
(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 our Galena Park Marine terminal that are destined for international markets. |
Three Months Ended September 30, 2015March 31, 2016 Compared to Three Months Ended September 30, 2014
Logistics Assetsand marketing gross margin decreased primarily due to lower fractionation margin, the realization of contract renegotiation fees earned in 2015, lower LPG export margin, and fractionation margin,lower terminaling and storage throughput, partially offset by a recognition of a portion of the renegotiated commercial arrangements related to our condensate splitter project and increased terminaling and storage activities. The lower export margin was partially due to LPG export volumes, which benefit both the Logistics Assets and Marketing and Distribution segments, which averaged 184.1 MBbl/d in the third quarter of 2015 compared to 205.9 MBbl/d for the same period last year.marketing gains. Fractionation gross margin was impacted bydecreased due to lower supply volume and a decrease in supply volume andsystem product gains, partially offset by the variable effects of fuel and power which are largely reflected in lower operating expenses (see footnote (1)(2) above). Terminaling and storage volumes increased due to higher customer throughput.
Operating expenses (see footnote (1) above) partially offset by an increase in supply volume. LPG export volumes, which benefit both the Logistics Assets and Marketing and Distribution segments, averaged 180.0 MBbl/d in 2015 compared to 160.5 MBbl/d for 2014.
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||||||||
2015 | 2014 | 2015 vs. 2014 | 2015 | 2014 | 2015 vs. 2014 | |||||||||||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||||||||||
Gross margin | $ | 70.2 | $ | 73.8 | $ | (3.6 | ) | 5 | % | $ | 209.4 | $ | 217.2 | $ | (7.8 | ) | 4 | % | ||||||||||||||
Operating expenses | 10.0 | 12.2 | (2.2 | ) | 18 | % | 32.1 | 37.7 | (5.6 | ) | 15 | % | ||||||||||||||||||||
Operating margin | $ | 60.2 | $ | 61.6 | $ | (1.4 | ) | 2 | % | $ | 177.3 | $ | 179.5 | $ | (2.2 | ) | 1 | % | ||||||||||||||
Operating statistics (1): | ||||||||||||||||||||||||||||||||
NGL sales, MBbl/d | 401.1 | 444.3 | (43.2 | ) | 10 | % | 426.1 | 405.5 | 20.6 | 5 | % | |||||||||||||||||||||
Average realized prices: | ||||||||||||||||||||||||||||||||
NGL realized price, $/gal | 0.41 | 0.95 | (0.54 | ) | 57 | % | 0.47 | 1.00 | (0.53 | ) | 53 | % |
Other
|
| Three Months Ended March 31, |
|
|
|
|
| |||||
|
| 2016 |
|
| 2015 |
|
| 2016 vs. 2015 |
| |||
|
| ($ in millions) |
| |||||||||
Gross margin |
| $ | 26.8 |
|
| $ | 21.7 |
|
| $ | 5.1 |
|
Operating margin |
| $ | 26.8 |
|
| $ | 21.7 |
|
| $ | 5.1 |
|
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||
2015 | 2014 | 2015 vs. 2014 | 2015 | 2014 | 2015 vs. 2014 | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||
Gross margin | $ | 21.8 | $ | (2.3 | ) | $ | 24.1 | $ | 60.7 | $ | (12.4 | ) | $ | 73.1 | ||||||||||
Operating margin | $ | 21.8 | $ | (2.3 | ) | $ | 24.1 | $ | 60.7 | $ | (12.4 | ) | $ | 73.1 |
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. Eliminations of inter-segment transactions are reflected in the corporate and eliminations column. The primary purpose of our commodity risk management activities is to mitigate a portion of the impact of commodity prices on our operating cash flow. We have hedged the commodity price associated with a portion of our expected (i) natural gas equity volumes in Field Gathering and Processing Operations and (ii) NGL and condensate equity volumes predominately in Field Gathering and Processing as well as in the LOU portion of the Coastalour Gathering and Processing Operations that result from percent of proceeds or liquid processing arrangements by entering into derivative instruments. Because we are essentially forward-selling a portion of our plant equity volumes, these hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices.
|
| Three Months Ended March 31, 2016 |
|
| Three Months Ended March 31, 2015 |
|
|
|
|
| ||||||||||||||||||
|
| (In millions, except volumetric data and price amounts) |
|
|
|
|
| |||||||||||||||||||||
|
| Volume Settled |
|
| Price Spread (1) |
|
| Gain (Loss) |
|
| Volume Settled |
|
| Price Spread (1) |
|
| Gain (Loss) |
|
| 2016 vs. 2015 |
| |||||||
Natural Gas (BBtu) |
|
| 19.6 |
|
| $ | 0.67 |
|
| $ | 13.2 |
|
|
| 7.6 |
|
| $ | 0.88 |
|
| $ | 6.7 |
|
| $ | 6.5 |
|
NGL (Mgal) |
|
| 26.2 |
|
|
| 0.15 |
|
|
| 3.8 |
|
|
| 10.3 |
|
|
| 0.30 |
|
|
| 3.1 |
|
|
| 0.7 |
|
Crude Oil (MBbl) |
|
| 0.3 |
|
|
| 23.67 |
|
|
| 7.1 |
|
|
| 0.2 |
|
|
| 26.50 |
|
|
| 5.3 |
|
|
| 1.8 |
|
Non-Hedge Accounting (2) |
|
|
|
|
|
|
|
|
|
| 2.7 |
|
|
|
|
|
|
|
|
|
|
| 5.6 |
|
|
| (2.9 | ) |
Ineffectiveness (3) |
|
|
|
|
|
|
|
|
|
| 0.0 |
|
|
|
|
|
|
|
|
|
|
| 1.0 |
|
|
| (1.0 | ) |
|
|
|
|
|
|
|
|
|
| $ | 26.8 |
|
|
|
|
|
|
|
|
|
| $ | 21.7 |
|
| $ | 5.1 |
|
Three Months Ended September 30, 2015 | Three Months Ended September 30, 2014 | |||||||||||||||||||||||||||
(In millions, except volumetric data and price amounts) | ||||||||||||||||||||||||||||
Volume Settled | Price Spread (1)(2) | Gain (Loss) | Volume Settled | Price Spread (1)(2) | Gain (Loss) | 2015 vs. 2014 | ||||||||||||||||||||||
Natural Gas (BBtu) | 16.2 | $ | 0.48 | $ | 7.7 | 6.1 | $ | (0.02 | ) | $ | (0.1 | ) | $ | 7.8 | ||||||||||||||
NGL (MMBbl) | 0.6 | 14.72 | 8.5 | 7.3 | 0.07 | 0.5 | 8.0 | |||||||||||||||||||||
Crude Oil (MMBbl) | 0.2 | 33.50 | 6.7 | 0.2 | (5.36 | ) | (1.1 | ) | 7.8 | |||||||||||||||||||
Non-Hedge Accounting (3) | (1.7 | ) | (1.6 | ) | (0.1 | ) | ||||||||||||||||||||||
Ineffectiveness (4) | 0.6 | - | 0.6 | |||||||||||||||||||||||||
$ | 21.8 | $ | (2.3 | ) | $ | 24.1 |
Nine Months Ended September 30, 2015 | Nine Months Ended September 30, 2014 | |||||||||||||||||||||||||||
(In millions, except volumetric data and price amounts) | ||||||||||||||||||||||||||||
Volume Settled | Price Spread (1)(2) | Gain (Loss) | Volume Settled | Price Spread (1)(2) | Gain (Loss) | 2015 vs. 2014 | ||||||||||||||||||||||
Natural Gas (BBtu) | 35.0 | $ | 0.65 | $ | 22.6 | 15.9 | $ | (0.44 | ) | $ | (6.9 | ) | $ | 29.5 | ||||||||||||||
NGL (MMBbl) | 62.4 | 0.29 | 18.1 | 15.9 | 0.04 | 0.7 | 17.4 | |||||||||||||||||||||
Crude Oil (MMBbl) | 0.7 | 19.71 | 13.8 | 0.7 | (7.74 | ) | (5.3 | ) | 19.1 | |||||||||||||||||||
Non-Hedge Accounting (3) | 4.9 | �� | (1.0 | ) | 5.9 | |||||||||||||||||||||||
Ineffectiveness (4) | 1.3 | 0.1 | 1.2 | |||||||||||||||||||||||||
$ | 60.7 | $ | (12.4 | ) | $ | 73.1 |
(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 Partnershipus and included in the acquisition date fair value of assets acquired. Derivative settlements of $20.7 million and $52.2$67.9 million related to these novated contracts were received during the threeyear ended December 31, 2015 and nine months$8.7 million related to these novated contracts were received during the quarter ended September 30, 2015March 31, 2016 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.
Liquidity and Capital Resources
Our ability to finance our operations, including funding capital expenditures and acquisitions, meeting our indebtedness obligations, refinancing our indebtedness and meeting our collateral requirements, will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control. These include weather, commodity prices (particularly for natural gas and NGLs) and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.
Our main sources of liquidity and capital resources are internally generated cash flow from operations, contributions from TRC, borrowings under the TRP Revolver, borrowings under the Securitization Facility, the issuance of additional Preferred Units or common units and access to debt markets. The capital markets continue to experience volatility. Our exposure to current credit conditions includes our credit facility, cash investments and counterparty performance risks. We continually monitor our liquidity and the credit markets, as well as events and circumstances surrounding each of the lenders to the TRP Revolver and Securitization Facility.
Our liquidity as of September 30, 2015April 19, 2016 was:
|
|
| April 19, 2016 |
| |
|
|
| (In millions) |
| |
Cash on hand |
| $ | 134.9 |
| |
Total commitments under the TRP Revolver |
|
| 1,600.0 |
| |
Total availability under the Securitization Facility |
|
| 206.5 |
| |
|
|
| 1,941.4 |
| |
|
|
|
|
| |
Less: | Outstanding borrowings under the TRP Revolver |
|
| (50.0 | ) |
| Outstanding borrowings under the Securitization Facility |
|
| (206.5 | ) |
| Outstanding letters of credit under the TRP Revolver |
|
| (12.2 | ) |
| Total liquidity |
| $ | 1,672.7 |
|
September 30, 2015 | ||||
(In millions) | ||||
Cash on hand | $ | 92.8 | ||
Total commitments under the TRP Revolver | 1,600.0 | |||
Total commitments under the Securitization Facility | 135.5 | |||
1,828.3 | ||||
Less: Outstanding borrowings under the TRP Revolver | (435.0 | ) | ||
Outstanding borrowings under the Securitization Facility | (135.5 | ) | ||
Outstanding letters of credit under the TRP Revolver | (11.2 | ) | ||
Total liquidity | $ | 1,246.6 |
Other potential capital resources include:
· | our right to request an additional $300 million in commitment increases under the TRP Revolver, subject to the terms therein. The |
Senior Notes | Outstanding Note Balance | Amount Tendered | Premium Paid | Accrued Interest Paid | Total Tender Offer payments | % Tendered | Note Balance after Tender Offers | |||||||||||||||||||||
($ amounts in millions) | ||||||||||||||||||||||||||||
6⅝% due 2020 | $ | 500.0 | $ | 140.1 | $ | 2.1 | $ | 3.7 | $ | 145.9 | 28.02 | % | $ | 359.9 | ||||||||||||||
4¾% due 2021 | 400.0 | 393.5 | 5.9 | 5.3 | 404.7 | 98.38 | % | 6.5 | ||||||||||||||||||||
5⅞% due 2023 | 650.0 | 601.9 | 8.7 | 2.6 | 613.2 | 92.60 | % | 48.1 | ||||||||||||||||||||
Total | $ | 1,550.0 | $ | 1,135.5 | $ | 16.7 | $ | 11.6 | $ | 1,163.8 | $ | 414.5 |
Working Capital
Working capital is the amount by which current assets exceed current liabilities. On a consolidated basis at the end of any given month, accounts receivable and payable tied to commodity sales and purchases are relatively balanced with receivables from NGL customers offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported total working capital are: (1) our cash position; (2) liquids inventory levels and valuation, which we closely manage; (3) changes in the fair value of the current portion of derivative contracts; and (4) major structural changes in our asset base or business operations, such as acquisitions or divestitures and certain organic growth projects.
Our working capital, increased $66.1 million excluding the decrease inexclusive of current debt obligations.obligations, decreased $77.2 million. The major items contributing to this non-debt changedecrease were an increaselower inventory volumes, decreased cash balances, decreased commodity activity and a decrease in our net risk management working capital asset position due to changes in the forward prices of commoditiescommodities. Partially offsetting these items were decreased capital accruals on a lower capital expenditure program, a decrease in accrued interest primarily due to debt repurchases and increased cash balances. Other factors included increased billing accruals related to the Badlands development projects, decreased payables to ParentParent. The decrease of $69.3 million in current debt obligations was due to the timing of annual compensation payments, and the inclusion of the working capital balancelower receivables available for TPL, offset by decreased commodity inventories due to falling prices and an increase in ad valorem tax accruals.
Based on our anticipated levels of operations and absent any disruptive events, we believe that internally generated cash flow, contributions from TRC, borrowings available under the TRP Revolver and the Securitization Facility and proceeds from equity offerings and debt offerings should provide sufficient resources to finance our operations, capital expenditures, long-term debt obligations , collateral requirements and minimum quarterly cash distributions to Targa for at least the next twelve months.
Cash Flow
Cash Flow from Operating Activities
Three Months Ended March 31, |
|
|
|
|
| |||||
2016 |
|
| 2015 |
|
| 2016 vs. 2015 |
| |||
(In millions) |
| |||||||||
$ | 242.0 |
|
| $ | 290.8 |
|
| $ | (48.8 | ) |
Nine Months Ended September 30, | |||||||||||
2015 | 2014 | 2015 vs. 2014 | |||||||||
(In millions) | |||||||||||
$ | 737.8 | $ | 571.8 | $ | 166.0 |
Nine Months Ended September 30, | ||||||||||||
2015 | 2014 | 2015 vs. 2014 | ||||||||||
(In millions) | ||||||||||||
Cash flows from operating activities: | ||||||||||||
Cash received from customers | $ | 5,039.0 | $ | 6,575.8 | $ | (1,536.8 | ) | |||||
Cash received from (paid to) derivative counterparties | 101.3 | (12.2 | ) | 113.5 | ||||||||
Cash outlays for: | ||||||||||||
Product purchases | 3,849.8 | 5,539.1 | (1,689.3 | ) | ||||||||
Operating expenses | 265.8 | 265.0 | 0.8 | |||||||||
General and administrative expenses | 138.1 | 111.0 | 27.1 | |||||||||
Cash distributions from equity investment (1) | (10.1 | ) | (13.8 | ) | 3.7 | |||||||
Interest paid, net of amounts capitalized (2) | 147.6 | 88.2 | 59.4 | |||||||||
Income taxes paid, net of refunds | 4.1 | 2.2 | 1.9 | |||||||||
Other cash (receipts) payments | 7.2 | 0.1 | 7.1 | |||||||||
Net cash provided by operating activities | $ | 737.8 | $ | 571.8 | $ | 166.0 |
Lower commodity prices were the primary contributor to decreased cash collections and payments for product purchases in 20152016 compared to 2014. Derivatives were2015. The inclusion of a net inflowfull quarter of operations for TPL in 2016 compared to one month in 2015 versus a net outflow in 2014 reflecting lower commodity prices paid to counterparties comparedcontributed to the fixed price we received on those derivative contracts. Higherincrease in cash outlayoperating expenses. Cash payment for general and administrative expensescompensation related costs were lower in 2015 versus 2014 was mainly due to the addition of general and administrative costs for TPL. Higher cash interest paid was primarily due to higher debt borrowings. Other cash payments during 2015 reflect transaction costs related to the Atlas mergers.
Cash Flow from Investing Activities
Three Months Ended March 31, |
|
|
|
|
|
| |||||
2016 |
|
| 2015 |
|
| 2016 vs. 2015 |
|
| |||
(In millions) | |||||||||||
$ | (188.0 | ) |
| $ | (1,016.3 | ) |
| $ | 828.3 |
|
|
Nine Months Ended September 30, | |||||||||||
2015 | 2014 | 2015 vs. 2014 | |||||||||
(In millions) | |||||||||||
$ | (1,462.5 | ) | $ | (561.2 | ) | $ | (901.3 | ) |
The increasedecrease in net cash used in investing activities for 20152016 compared to 20142015 was primarily due to the $828.7 million cash outlaysoutlay for the cash portion of Atlas mergers along with a $53.6 million increase in capital expenditures.
Cash Flow from Financing Activities
Three Months Ended March 31, |
|
|
|
|
|
| |||||
2016 |
|
| 2015 |
|
|
| 2016 vs. 2015 |
| |||
(In millions) |
| ||||||||||
$ | (86.1 | ) |
| $ | 718.4 |
|
|
| $ | (804.5 | ) |
Nine Months Ended September 30, | |||||||||||
2015 | 2014 | 2015 vs. 2014 | |||||||||
(In millions) | |||||||||||
$ | 745.2 | $ | 4.3 | $ | 740.9 |
We received a capital contribution of $801.0 million from TRC in March 2016. Proceeds from this contribution were used to for net debt repayments and redemptions of senior notes in 2016 ($679.8 million) and other general partnership purposes. In 2015, net cash provided by financing activities for 2015 compared to 2014 was primarily due to the Atlas mergers, including the issuance of senior notes ($1.1 billion),included net borrowings under our debt facilities ($819.4 million) and payments to settle the tender for APL’s senior notes ($1,168.8786.3 million). During the third quarter of 2015, we had additional note issuances of $600.0 million and net repayments under our debt facilities of $431.7 million. Distributions to unitholdersunit holders increased by $65.1 million in 2015 ($169.8 million).2016.
Distributions to our Unitholders
We distribute all available cash, after the preferred distribution,distributions on the Preferred Units, from our operating surplus. As a result, we expect that we will rely upon external financing sources, including debt and common unit issuances, to fund our acquisition and expansion capital expenditures. See Notes 10Note 9 – Debt Obligations and Note 11 – Partnership Units and Related Matters of the “Consolidated Financial Statements” included in this Quarterly Report.
The following table details the distributions declared and/orand paid, net of the IDR Giveback, during the ninethree months ended September 30, 2015:March 31, 2016 and for the three months ended December 31, 2015.
|
|
|
| Distributions |
|
|
|
|
|
|
|
|
| |||||||||||||
|
|
|
| Limited Partners |
|
| General Partner |
|
|
|
|
|
|
|
|
|
|
| ||||||||
Three Months Ended |
| Date Paid |
| Common |
|
| Incentive |
|
|
| 2% |
|
| Total |
|
| Distributions to Targa Resources Corp. |
|
| Distributions per Limited Partner Unit |
| |||||
|
|
|
| (In millions, except per unit amounts) |
| |||||||||||||||||||||
December 31, 2015 |
| February 9, 2016 |
| $ | 152.5 |
|
| $ | 43.9 |
|
| $ | 4.0 |
|
| $ | 200.4 |
|
| $ | 61.4 |
|
| $ | 0.8250 |
|
Distributions | |||||||||||||||||||||||
Three Months Ended | Date Paid or to be Paid | Limited Partners | General Partner | Distributions per Limited Partner Unit | |||||||||||||||||||
Common | Incentive Distribution Rights | 2% | Total | ||||||||||||||||||||
(In millions, except per unit amounts) | |||||||||||||||||||||||
September 30, 2015 | November 13, 2015 | $ | 152.5 | $ | 43.9 | (1) | $ | 4.0 | $ | 200.4 | $ | 0.8250 | |||||||||||
June 30, 2015 | August 14, 2015 | 152.5 | 43.9 | (1) | 4.0 | 200.4 | 0.8250 | ||||||||||||||||
March 31, 2015 | May 15, 2015 | 148.3 | 41.7 | (1) | 3.9 | 193.9 | 0.8200 | ||||||||||||||||
December 31, 2014 | February 13, 2015 | 96.3 | 38.4 | 2.7 | 137.4 | 0.8100 |
Total distributions declared as of March 31, 2016 to be paid to TRC on May 12, 2016 are $154.8 million. As a result of the TRC/TRP Merger, TRC is entitled to receive all our distributions, other than distributions for the preferred Series A units, for the quarter ended March 31, 2016 and all future quarters.
Distributions are declared and paid monthly on our outstanding preferred Series A units. For the three months ended March 31, 2016 $2.8 million of distributions were paid. We have accrued distributions to preferred Series A unitholders of $0.9 million for March 2016, which were paid subsequently on April 20, 2016.
Subsequent Event
On April 19, 2016, our board of directors of the general partner declared a monthly cash distribution of $0.1875 per preferred Series A Unit for April 2016. This distribution will be paid on May 16, 2016.
Capital Requirements
Our capital requirements relate to capital expenditures, which are classified as expansion expenditures, which include business acquisitions, or maintenance expenditures. Expansion capital expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, reduce costs or enhance revenues, and fund acquisitions of businesses or assets. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets, including the replacement of system components and equipment, which are worn, obsolete or completing their useful life and expenditures to remain in compliance with environmental laws and regulations.
|
| Three Months Ended March 31, |
| |||||
|
| 2016 |
|
| 2015 |
| ||
Capital expenditures : |
| (In millions) |
| |||||
Consideration for business acquisitions |
| $ | — |
|
| $ | 5,024.2 |
|
Non-cash value of acquisition (1) |
|
| — |
|
|
| (2,583.1 | ) |
Non-cash Targa contribution, Special General Partner interest (1) |
|
| — |
|
|
| (1,612.4 | ) |
Business acquisitions, net of cash acquired |
|
| — |
|
|
| 828.7 |
|
Expansion |
|
| 161.9 |
|
|
| 137.0 |
|
Maintenance |
|
| 15.0 |
|
|
| 20.3 |
|
Gross capital expenditures |
|
| 176.9 |
|
|
| 157.3 |
|
Transfers from materials and supplies inventory to property, plant and equipment |
|
| (0.5 | ) |
|
| (0.6 | ) |
Decrease in capital project payables and accruals |
|
| 13.7 |
|
|
| 31.0 |
|
Cash outlays for capital projects |
|
| 190.1 |
|
|
| 187.7 |
|
Targa cash consideration, ATLS merger |
|
| — |
|
|
| 745.6 |
|
Total |
| $ | 190.1 |
|
| $ | 1,762.0 |
|
Nine Months Ended September 30, | ||||||||
2015 | 2014 | |||||||
Capital expenditures : | (In millions) | |||||||
Consideration for business acquisitions | $ | 5,024.2 | $ | - | ||||
Non-cash consideration APL merger | (2,583.1 | ) | - | |||||
Non-cash Targa contribution, Special General Partner interest (1) | (1,612.4 | ) | - | |||||
Cash consideration for business acquisitions, net of cash acquired | 828.7 | - | ||||||
Expansion | 497.9 | 478.2 | ||||||
Maintenance | 73.1 | 55.6 | ||||||
Gross capital expenditures | 571.0 | 533.8 | ||||||
Transfers from materials and supplies inventory to property, plant and equipment | (2.9 | ) | (2.7 | ) | ||||
Decrease (increase) in capital project payables and accruals | 57.2 | 40.6 | ||||||
Cash outlays for capital projects | 625.3 | 571.7 | ||||||
Targa cash consideration, ATLS merger | 745.6 | - | ||||||
$ | 2,199.6 | $ | 571.7 |
(1) | Includes the non-cash value of consideration and the Special GP Interest |
We currently estimate that our totalwe will invest $525 million or less in net growth capital expenditures on a gross basis, will be approximately $700.0 million to $800.0 million for 2015 and approximately $600 million for 2016, and maintenance capital expenditures net to our interest will be approximately $100 million to $110 million for 2015 andannounced projects in 2016. Given our objective of growth through expansions of existing assets, other internal growth projects, and acquisitions, we anticipate that over time that we will invest significant amounts of capital to grow and acquire assets. Future expansion capital expenditures may vary significantly based on investment opportunities. We expect to fund future capital expenditures with funds generated from our operations, borrowings under the TRP Revolver and the Securitization Facility and proceeds from issuances of additional equity and debt securities.
Critical Accounting Policies and Estimates
Our critical accounting policies and estimates are set forth in Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report. We have updated our accountingThere were no significant updates or revisions to these policies during the ninethree months ended September 30, 2015 in Note 3 of the “Consolidated Financial Statements” in this Quarterly Report to include our accounting policy for goodwill.
Off-Balance Sheet Arrangements
As of September 30, 2015,March 31, 2016, there were $25.4$33.3 million in surety bonds outstanding related to various performance obligations. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate, (ii) surety, and (iii) counterparty support. Obligations under these surety bonds are not normally called, as we typically comply with the underlying performance requirement.
Contractual Obligations
As of September 30, 2015,March 31, 2016, there have been no significant changes in the contractual obligations as presented in our 20142015 Form 10-K, except as noted for those acquired in the Atlas mergers,debt repurchases which were previouslyare disclosed in Note 9 – Debt Obligations in our Form 10-Q for the quarter ended March 31, 2015.
Commodity Price Risk
Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil, changes in interest rates, as well as nonperformance by our customers.
A significant portion of our revenues isare derived from percent-of-proceeds contracts under which we receive a portion of the natural gas and/or NGLs or equity volumes as payment for services. The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged.
The primary purpose of ourthe commodity risk management activities is to hedge some of the exposure to commodity price risk and reduce volatilityfluctuations in our operating cash flowsflow due to fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of September 30, 2015,March 31, 2016, we have hedged the commodity price associated with a portion of our expected (i) natural gas equity volumes in Fieldour Gathering and Processing Operationsoperations and (ii) NGL and condensate equity volumes predominately in Fieldour Gathering and Processing Operations, as well as in the LOU portion of the Coastal Gathering and Processing Operations,operations that result from our percent-of-proceeds processing arrangements by entering into derivative instruments. We hedge a higher percentage of our expected equity volumes in the current year compared to future years, infor which we hedge incrementally lower percentages of expected equity volumes. With swaps, we typically receive an agreed fixed price for a specified notional quantity of natural gas or NGLs and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We may buy calls in connection with swap positions to create a price floor with upside. We intend to continue to manage our exposure to commodity prices in the future by entering into derivative transactions using swaps, collars, purchased puts (or floors) or other derivative instruments as market conditions permit.
When entering into new hedges, we intend to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. The NGL hedges cover specific NGL products based upon the expected equity NGL
52
composition. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. The natural gas and NGL hedges’ fair values are based on published index prices for delivery at various locations whichand we seek to closely approximate the actual natural gas and NGL delivery points. A portion of our condensate sales are hedged using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude.
These commodity price-hedgingprice hedging transactions are typically documented pursuant to a standard International Swap Dealers Association form with customized credit and legal terms. OurThe principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. Our payment obligations in connection with substantially all of these hedging transactions and any additional credit exposure due to a rise in natural gas and NGL prices relative to the fixed prices set forth in the hedges are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. Absent federal regulations resulting from the Dodd-Frank Act, and as long as this first priority lien is in effect, we expect to have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time, even if oura counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness. A purchased put (or floor) transaction does not expose our counterparties to credit risk, as we have no obligation to make future payments beyond the premium paid to enter into the transaction; however, we are exposed to the risk of default by the counterparty, which is the risk that the counterparty will not honor its obligation under the put transaction.
For all periods presented, we have entered into hedging arrangements for a portion of our forecasted equity volumes. During the three months ended September 30,March 31, 2016 and 2015, and 2014 our operating revenues increased (decreased) by net hedge adjustments on commodity derivative contracts of $21.8$26.8 million and $(2.3)$21.7 million. During the nine months ended September 30, 2015 and 2014, our operating revenues increased (decreased) by net hedge adjustments on commodity derivative contracts of $60.7 million and $(12.4) million.
Natural GAS
Instrument |
| Price |
|
|
|
| MMBtu/d |
|
|
|
|
| ||||||||||
Type | Index | $/MMBtu |
|
|
|
| 2016 |
|
| 2017 |
|
| 2018 |
|
| Fair Value |
| |||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| (In millions) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap | IF-NGPL MC |
| 3.93 |
|
|
|
|
| 3,456 |
|
|
| - |
|
|
| - |
|
| $ | 1.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap | IF-Waha |
| 3.17 |
|
|
|
|
| 39,436 |
|
|
| - |
|
|
| - |
|
|
| 11.8 |
|
Swap | IF-Waha |
| 2.68 |
|
|
|
|
| - |
|
|
| 25,000 |
|
|
| - |
|
|
| 0.1 |
|
Swap | IF-Waha |
| 2.43 |
|
|
|
|
| - |
|
|
| - |
|
|
| 20,000 |
|
|
| (2.8 | ) |
|
|
|
|
|
|
|
|
| 39,436 |
|
|
| 25,000 |
|
|
| 20,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Put Price |
| Call Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Collar | IF-Waha |
| 2.85 |
|
| 3.47 |
|
| 7,500 |
|
|
| - |
|
|
| - |
|
|
| 1.7 |
|
Collar | IF-Waha |
| 3.00 |
|
| 3.67 |
|
| - |
|
|
| 7,500 |
|
|
| - |
|
|
| 1.2 |
|
Collar | IF-Waha |
| 3.25 |
|
| 4.20 |
|
| - |
|
|
| - |
|
|
| 1,849 |
|
|
| 0.3 |
|
|
|
|
|
|
|
|
|
| 7,500 |
|
|
| 7,500 |
|
|
| 1,849 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap | IF-PB |
| 3.12 |
|
|
|
|
| 18,508 |
|
|
| - |
|
|
| - |
|
|
| 5.5 |
|
Swap | IF-PB |
| 2.51 |
|
|
|
|
| - |
|
|
| 10,900 |
|
|
| - |
|
|
| (0.5 | ) |
Swap | IF-PB |
| 2.51 |
|
|
|
|
| - |
|
|
| - |
|
|
| 10,900 |
|
|
| (1.0 | ) |
|
|
|
|
|
|
|
|
| 18,508 |
|
|
| 10,900 |
|
|
| 10,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Put Price |
| Call Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Collar | IF-PB |
| 2.65 |
|
| 3.31 |
|
| 15,400 |
|
|
| - |
|
|
| - |
|
|
| 2.8 |
|
Collar | IF-PB |
| 2.80 |
|
| 3.50 |
|
| - |
|
|
| 15,400 |
|
|
| - |
|
|
| 1.8 |
|
Collar | IF-PB |
| 3.00 |
|
| 3.65 |
|
| - |
|
|
| - |
|
|
| 7,637 |
|
|
| 1.0 |
|
|
|
|
|
|
|
|
|
| 15,400 |
|
|
| 15,400 |
|
|
| 7,637 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap | NG-NYMEX |
| 4.12 |
|
|
|
|
| 31,531 |
|
|
| - |
|
|
| - |
|
|
| 16.4 |
|
Swap | NG-NYMEX |
| 4.11 |
|
|
|
|
| - |
|
|
| 18,082 |
|
|
| - |
|
|
| 8.6 |
|
|
|
|
|
|
|
|
|
| 31,531 |
|
|
| 18,082 |
|
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis Swap | EP_PERMIAN |
| (0.1702 | ) |
|
|
|
| 15,818 |
|
|
| - |
|
|
| - |
|
|
| 0.1 |
|
Basis Swap | EP_PERMIAN |
| (0.1444 | ) |
|
|
|
| - |
|
|
| 9,041 |
|
|
| - |
|
|
| (0.1 | ) |
|
|
|
|
|
|
|
|
| 15,818 |
|
|
| 9,041 |
|
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis Swap | PEPL |
| (0.3278 | ) |
|
|
|
| 15,818 |
|
|
| - |
|
|
| - |
|
|
| (0.4 | ) |
Basis Swap | PEPL |
| (0.3308 | ) |
|
|
|
| - |
|
|
| 9,041 |
|
|
| - |
|
|
| (0.4 | ) |
|
|
|
|
|
|
|
|
| 15,818 |
|
|
| 9,041 |
|
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
|
| 147,467 |
|
|
| 94,964 |
|
|
| 40,386 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 47.9 |
|
54
Instrument |
| Price |
|
|
|
| Bbl/d |
|
|
|
|
| ||||||||||
Type | Index | $/Bbl |
|
|
|
| 2016 |
|
| 2017 |
|
| 2018 |
|
| Fair Value |
| |||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| (In millions) |
| |
Swap | C2-OPIS-MB |
| 0.2209 |
|
|
|
|
| 870 |
|
|
| - |
|
|
| - |
|
| $ | 0.4 |
|
Swap | C2-OPIS-MB |
| 0.2294 |
|
|
|
|
| - |
|
|
| 870 |
|
|
| - |
|
|
| 0.0 |
|
Swap | C2-OPIS-MB |
| 0.2371 |
|
|
|
|
| - |
|
|
| - |
|
|
| 658 |
|
|
| (0.1 | ) |
Total |
|
|
|
|
|
|
|
| 870 |
|
|
| 870 |
|
|
| 658 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future | C2-OPIS-MB |
| 0.1792 |
|
|
|
|
| 1,236 |
|
|
| - |
|
|
| - |
|
|
| (0.4 | ) |
Future | C2-OPIS-MB |
| 0.1856 |
|
|
|
|
| - |
|
|
| 274 |
|
|
| - |
|
|
| (0.1 | ) |
Total |
|
|
|
|
|
|
|
| 1,236 |
|
|
| 274 |
|
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap | C3-OPIS-MB |
| 0.7890 |
|
|
|
|
| 3,782 |
|
|
| - |
|
|
| - |
|
|
| 14.1 |
|
Swap | C3-OPIS-MB |
| 1.0400 |
|
|
|
|
| - |
|
|
| 658 |
|
|
| - |
|
|
| 5.7 |
|
Total |
|
|
|
|
|
|
|
| 3,782 |
|
|
| 658 |
|
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future | C3-OPIS-MB |
| 0.4413 |
|
|
|
|
| 2,822 |
|
|
| - |
|
|
| - |
|
|
| (1.3 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future | NC4-OPIS-MB |
| 0.5165 |
|
|
|
|
| 273 |
|
|
| - |
|
|
| - |
|
|
| (0.2 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap | C5-OPIS-MB |
| 0.8825 |
|
|
|
|
| 160 |
|
|
| - |
|
|
| - |
|
|
| (0.0 | ) |
Swap | C5-OPIS-MB |
| 0.8825 |
|
|
|
|
| - |
|
|
| 160 |
|
|
| - |
|
|
| (0.1 | ) |
Swap | C5-OPIS-MB |
| 0.8825 |
|
|
|
|
| - |
|
|
| - |
|
|
| 160 |
|
|
| (0.1 | ) |
Total |
|
|
|
|
|
|
|
| 160 |
|
|
| 160 |
|
|
| 160 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Put Price |
| Call Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Collar | C2-OPIS-MB |
| 0.200 |
|
| 0.235 |
|
| 410 |
|
|
| - |
|
|
| - |
|
|
| 0.1 |
|
Collar | C2-OPIS-MB |
| 0.240 |
|
| 0.290 |
|
| - |
|
|
| 410 |
|
|
| - |
|
|
| 0.2 |
|
Total |
|
|
|
|
|
|
|
| 410 |
|
|
| 410 |
|
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Put Price |
| Call Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Collar | C3-OPIS-MB |
| 0.560 |
|
| 0.68000 |
|
| 380 |
|
|
| - |
|
|
| - |
|
|
| 0.5 |
|
Collar | C3-OPIS-MB |
| 0.570 |
|
| 0.68625 |
|
| - |
|
|
| 380 |
|
|
| - |
|
|
| 0.7 |
|
Total |
|
|
|
|
|
|
|
| 380 |
|
|
| 380 |
|
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Put Price |
| Call Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Collar | C5-OPIS-MB |
| 1.200 |
|
| 1.390 |
|
| 130 |
|
|
| - |
|
|
| - |
|
|
| 0.5 |
|
Collar | C5-OPIS-MB |
| 1.210 |
|
| 1.415 |
|
| - |
|
|
| 130 |
|
|
| - |
|
|
| 0.6 |
|
Collar | C5-OPIS-MB |
| 1.230 |
|
| 1.385 |
|
| - |
|
|
| - |
|
|
| 32 |
|
|
| 0.2 |
|
Total |
|
|
|
|
|
|
|
| 130 |
|
|
| 130 |
|
|
| 32 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
|
| 10,063 |
|
|
| 2,882 |
|
|
| 850 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 20.7 |
|
55
Natural Gas | |||||||||||||||||||||||||||||||||||||||||||||||||
Instrument | Price | MMBtu/d | |||||||||||||||||||||||||||||||||||||||||||||||
Instrument |
| Price |
|
|
| Bbl/d |
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||
Type | Index | $/MMBtu | 2015 | 2016 | 2017 | 2018 | Fair Value | Index | $/Bbl |
|
|
|
| 2016 |
|
| 2017 |
|
| 2018 |
|
| Fair Value |
| |||||||||||||||||||||||||
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| (In millions) |
| ||||||||||||||||||||||||||||||
Swap | IF-WAHA | 4.05 | 36,236 | - | - | - | $ | 4.1 | NY-WTI |
| 62.19 |
|
|
| 2,375 |
|
|
| - |
|
|
| - |
|
| $ | 13.4 |
| |||||||||||||||||||||
Swap | IF-WAHA | 3.94 | - | 19,436 | - | - | 7.9 | NY-WTI |
| 57.49 |
|
|
| - |
|
|
| 1,400 |
|
|
| - |
|
|
| 6.3 |
| ||||||||||||||||||||||
Swap | IF-WAHA | 3.69 | - | - | 5,000 | - | 1.4 | NY-WTI |
| 45.15 |
|
|
| - |
|
|
| - |
|
|
| 900 |
|
|
| (0.6 | ) | ||||||||||||||||||||||
Total Swaps | 36,236 | 19,436 | 5,000 | - | |||||||||||||||||||||||||||||||||||||||||||||
Swap | NY-WTI |
|
|
|
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 0.0 |
| ||||||||||||||||||||||||||||
|
|
|
|
|
|
| 2,375 |
|
|
| 1,400 |
|
|
| 900 |
|
|
|
|
| |||||||||||||||||||||||||||||
Swap | IF-PB | 4.01 | 14,576 | - | - | - | 2.0 | ||||||||||||||||||||||||||||||||||||||||||
Swap | IF-PB | 3.99 | - | 7,608 | - | - | 3.7 | ||||||||||||||||||||||||||||||||||||||||||
Total Swaps | 14,576 | 7,608 | - | - | |||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||
Swap | IF-NGPL MC | 3.84 | 4,739 | - | - | - | 0.6 | ||||||||||||||||||||||||||||||||||||||||||
Swap | IF-NGPL MC | 3.93 | - | 3,456 | - | - | 1.6 | ||||||||||||||||||||||||||||||||||||||||||
Total Swaps | 4,739 | 3,456 | - | - | - | ||||||||||||||||||||||||||||||||||||||||||||
- | - | ||||||||||||||||||||||||||||||||||||||||||||||||
Swap | NG-NYMEX | 4.14 | 71,318 | - | - | 10.1 | |||||||||||||||||||||||||||||||||||||||||||
Swap | NG-NYMEX | 4.15 | - | 37,705 | - | 18.5 | |||||||||||||||||||||||||||||||||||||||||||
Swap | NG-NYMEX | 4.11 | - | - | 18,082 | - | 7.0 | ||||||||||||||||||||||||||||||||||||||||||
Total Swaps | 71,318 | 37,705 | 18,082 | - | |||||||||||||||||||||||||||||||||||||||||||||
Total Natural Gas Swaps | 126,869 | 68,205 | 23,082 | - | |||||||||||||||||||||||||||||||||||||||||||||
56.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||
Put Price | Call Price |
| Put Price |
| Call Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||
Collar | IF-WAHA | 2.85 | 3.47 | - | 7,500 | - | - | 0.8 | NY-WTI |
| 57.08 |
| 67.97 |
| 790 |
|
|
| - |
|
|
| - |
|
|
| 3.4 |
| |||||||||||||||||||||
Collar | IF-WAHA | 3.00 | 3.67 | - | - | 7,500 | - | 0.7 | NY-WTI |
| 58.56 |
| 69.95 |
| - |
|
|
| 790 |
|
|
| - |
|
|
| 4.3 |
| |||||||||||||||||||||
Collar | IF-WAHA | 3.25 | 4.20 | - | - | - | 1,849 | 0.2 | NY-WTI |
| 60.00 |
| 71.60 |
| - |
|
|
| - |
|
|
| 101 |
|
|
| 0.6 |
| |||||||||||||||||||||
Total Collars | - | 7,500 | 7,500 | 1,849 | |||||||||||||||||||||||||||||||||||||||||||||
Collar | NY-WTI |
|
|
|
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 0.0 |
| ||||||||||||||||||||||||||||
|
|
|
|
|
|
| 790 |
|
|
| 790 |
|
|
| 101 |
|
|
|
|
| |||||||||||||||||||||||||||||
Collar | IF-PB | 2.55 | 3.10 | 15,400 | - | - | - | 0.2 | |||||||||||||||||||||||||||||||||||||||||
Collar | IF-PB | 2.65 | 3.31 | - | 15,400 | - | - | 1.1 | |||||||||||||||||||||||||||||||||||||||||
Collar | IF-PB | 2.80 | 3.50 | 15,400 | 1.0 | ||||||||||||||||||||||||||||||||||||||||||||
Collar | IF-PB | 3.00 | 3.65 | - | - | - | 7,637 | 0.6 | |||||||||||||||||||||||||||||||||||||||||
Total Collars | 15,400 | 15,400 | 15,400 | 7,637 | |||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||
Total Natural Gas Collars | 15,400 | 22,900 | 22,900 | 9,486 | |||||||||||||||||||||||||||||||||||||||||||||
Total Sales |
|
|
|
|
|
|
| 3,165 |
|
|
| 2,190 |
|
|
| 1,001 |
|
|
|
|
| ||||||||||||||||||||||||||||
$ | 61.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 27.4 |
|
NGL | |||||||||||||||||||||||||||
Instrument | Price | Bbl/d | |||||||||||||||||||||||||
Type | Index | $/Gal | 2015 | 2016 | 2017 | 2018 | Fair Value | ||||||||||||||||||||
(In millions) | |||||||||||||||||||||||||||
Swap | C2 OPIS-MB | 0.20 | 420 | - | - | - | $ | - | |||||||||||||||||||
Swap | C2 OPIS-MB | 0.21 | - | 420 | - | - | 0.1 | ||||||||||||||||||||
Swap | C2 OPIS-MB | 0.23 | - | - | 420 | - | 0.1 | ||||||||||||||||||||
Swap | C2 OPIS-MB | 0.26 | - | - | - | 208 | 0.1 | ||||||||||||||||||||
Total Swaps | 420 | 420 | 420 | 208 | |||||||||||||||||||||||
Swap | C3 OPIS-MB | 1.03 | 3,522 | - | - | - | $ | 7.6 | |||||||||||||||||||
Swap | C3 OPIS-MB | 1.03 | - | 2,254 | - | - | 19.2 | ||||||||||||||||||||
Swap | C3 OPIS-MB | 1.04 | - | - | 658 | - | 5.5 | ||||||||||||||||||||
Total Swaps | 3,522 | 2,254 | 658 | - | |||||||||||||||||||||||
Swap | C5 OPIS-MB | 2.00 | 326 | - | - | - | 1.3 | ||||||||||||||||||||
Total NGL Swaps | 4,268 | 2,674 | 1,078 | 208 | |||||||||||||||||||||||
Put Price | Call Price | ||||||||||||||||||||||||||
Collar | C2 OPIS-MB | 0.170 | 0.190 | 410 | - | - | - | - | |||||||||||||||||||
Collar | C2 OPIS-MB | 0.200 | 0.235 | - | 410 | - | - | 0.1 | |||||||||||||||||||
Collar | C2 OPIS-MB | 0.240 | 0.290 | - | - | 410 | - | 0.2 | |||||||||||||||||||
410 | 410 | 410 | - | ||||||||||||||||||||||||
Put Price | Call Price | ||||||||||||||||||||||||||
Collar | C3 OPIS-MB | 0.550 | 0.668 | 380 | - | - | - | 0.1 | |||||||||||||||||||
Collar | C3 OPIS-MB | 0.560 | 0.680 | - | 380 | - | - | 0.7 | |||||||||||||||||||
Collar | C3 OPIS-MB | 0.570 | 0.686 | - | - | 380 | - | 0.7 | |||||||||||||||||||
380 | 380 | 380 | - | ||||||||||||||||||||||||
Put Price | Call Price | ||||||||||||||||||||||||||
Collar | C5 OPIS-MB | 1.200 | 1.410 | 130 | - | - | - | 0.1 | |||||||||||||||||||
Collar | C5 OPIS-MB | 1.200 | 1.390 | - | 130 | - | - | 0.5 | |||||||||||||||||||
Collar | C5 OPIS-MB | 1.210 | 1.415 | - | - | 130 | - | 0.5 | |||||||||||||||||||
Collar | C5 OPIS-MB | 1.230 | 1.385 | - | - | - | 32 | 0.1 | |||||||||||||||||||
130 | 130 | 130 | 32 | ||||||||||||||||||||||||
Total Collars | 920 | 920 | 920 | 32 | |||||||||||||||||||||||
Total | 5,188 | 3,594 | 1,998 | 240 | |||||||||||||||||||||||
$ | 36.9 |
Condensate | |||||||||||||||||||||||||||
Instrument | Price | Bbl/d | |||||||||||||||||||||||||
Type | Index | $/Bbl | 2015 | 2016 | 2017 | 2018 | Fair Value | ||||||||||||||||||||
(In millions) | |||||||||||||||||||||||||||
Swap | NY-WTI | 81.56 | 1,663 | - | - | - | $ | 5.5 | |||||||||||||||||||
Swap | NY-WTI | 81.13 | - | 1,082 | - | - | 12.6 | ||||||||||||||||||||
Swap | NY-WTI | 79.70 | - | - | 500 | - | 4.8 | ||||||||||||||||||||
Total Swaps | 1,663 | 1,082 | 500 | - | |||||||||||||||||||||||
Put Price | Call Price | ||||||||||||||||||||||||||
Collar | NY-WTI | 53.19 | 66.03 | 790 | - | - | - | 0.6 | |||||||||||||||||||
Collar | NY-WTI | 57.08 | 67.97 | - | 790 | - | - | 2.8 | |||||||||||||||||||
Collar | NY-WTI | 58.56 | 69.95 | - | - | 790 | - | 2.5 | |||||||||||||||||||
Collar | NY-WTI | 60.00 | 71.60 | 101 | 0.4 | ||||||||||||||||||||||
Total Collars | 790 | 790 | 790 | 101 | |||||||||||||||||||||||
Total | 2,453 | 1,872 | 1,290 | 101 | |||||||||||||||||||||||
$ | 29.2 |
As of September 30, 2015March 31, 2016 we had the following derivative instruments that are not designated as hedges and are marked-to-marketmarked-to-market:
NATURAL GAS
Instrument |
| Price |
|
| MMBtu/d |
|
|
|
|
| ||||||||||
Type | Index | $/MMBtu |
|
| 2016 |
|
| 2017 |
|
| 2018 |
|
| Fair Value |
| |||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| (In millions) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis Swap | Various |
| 0.17 |
|
|
| 11,673 |
|
|
| - |
|
|
| - |
|
|
| (0.3 | ) |
GasDaily | HENRYHUBGD |
|
|
|
|
| (1,091 | ) |
|
| - |
|
|
| - |
|
|
| (0.0 | ) |
|
|
|
|
|
|
| 10,582 |
|
|
| - |
|
|
| - |
|
|
|
|
|
Natural Gas | ||||||||||||||||||||||||||
Instrument | Price | MMBtu/d | ||||||||||||||||||||||||
Type | Index | $/MMBtu | 2015 | 2016 | 2017 | 2018 | Fair Value | |||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||
Swap | IF-WAHA | 2.94 | 29,174 | 11,194 | - | - | $ | - | ||||||||||||||||||
Basis Swap | various | (0.19 | ) | 88,099 | 48,962 | 18,082 | - | (1.3 | ) | |||||||||||||||||
Transport (1) | various | 0.33 | 7,413 | - | - | - | (0.1 | ) | ||||||||||||||||||
$ | (1.4 | ) |
Condensate | ||||||||||||||||||||||||||
Instrument | Price | Bbl/d | ||||||||||||||||||||||||
Type | Index | $/Bbl | 2015 | 2016 | 2017 | 2018 | Fair Value | |||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||
Put Option (1) | NY-WTI | 88.15 | 815 | - | - | - | $ | 3.2 | ||||||||||||||||||
These contracts may expose us to the risk of financial loss in certain circumstances. Generally, our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which they have been hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges (other than with respect to purchased calls). For derivative instruments not designated as cash-flow hedges, these contracts are marked-to-market and recorded in revenues.
We account for the fair value of our financial assets and liabilities using a three-tier fair value hierarchy, which prioritizes the significant inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. We determine the value of our derivative contracts utilizing a discounted cash flow model for swaps and a standard option-pricing model for options based on inputs that are readily available in public markets. For futures contracts executed through a counterparty that clears the hedges through an exchange, the classification of these instruments is Level 1 within the fair value hierarchy. For the contracts that have inputs from quoted prices, the classification of these instruments is Level 2 within the fair value hierarchy. For those contracts which we are unable to obtain quoted prices for at least 90% of the full term of the commodity swap and options, the valuations are classified as Level 3 within the fair value hierarchy. See Note 14 of the “Consolidated Financial Statements” in this Quarterly Report for more information regarding classifications within the fair value hierarchy.
Interest Rate Risk
We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under the TRP Revolver and the Securitization Facility. As of September 30, 2015,March 31, 2016, we do not have any interest rate hedges. However, we may in the future enter into
56
interest rate hedges intended to mitigate the impact of changes in interest rates on cash flows. To the extent that interest rates increase, interest expense for the TRP Revolver and the Securitization Facility will also increase. As of September 30, 2015,March 31, 2016, we had $570.5$150.0 million in outstanding variable rate borrowings under the TRP Revolver and the Securitization Facility. A hypothetical change of 100 basis points in the interest rate of our variable rate debt would impact our annual interest expense by $5.7$1.5 million.
Counterparty Credit Risk
We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. The credit exposure related to commodity derivative instruments is represented by the fair value of the asset position (i.e. the fair value of expected future receipts) at the reporting date. Our futures contracts have limited credit risk since they are cleared through an exchange and are settled daily. Should the creditworthiness of one or more of the counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted. We have master netting provisions in the International Swap Dealers Association agreements with all of our derivative counterparties. These netting provisions allow us to net settle asset and liability positions with the same counterparties within the same Targa entity, and would reduce our maximum loss due to counterparty credit risk by $8.3$9.9 million as of September 30, 2015. March 31, 2016. The range of losses attributable to our individual counterparties would be between less than $0.1 million and $48.6$29.5 million, depending on the counterparty in default.
Customer Credit Risk
We extend credit to customers and other parties in the normal course of business. We have an established policy and various procedures to manage our credit exposure risk, including initial and subsequent credit risk analyses, credit limits and terms and credit enhancements when necessary. We use credit enhancements including (but not limited to) letters of credit, prepayments, parental guarantees and rights of offset to limit credit risk to ensure that our established credit criteria are followed and financial loss is mitigated or minimized.
We have an active credit management process, which is focused on controlling loss exposure to bankruptcies or other liquidity issues of counterparties. If an assessment of uncollectible accounts resulted in a 1% reduction of our third-party accounts receivable, annual operating income would decrease by $6.2$4.3 million in the year of the assessment.
Management, under the supervision of and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered byin this Quarterly Report. Based on suchthis evaluation, ourthe Chief Executive Officer and the Chief Financial Officer have concluded that as of September 30, 2015, our disclosure controls and procedures were designed at the reasonable assurance level and,not effective as a result of the end of the period covered by this Quarterly Report, our disclosure controls and procedures are effective at the reasonable assurance level to provide that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and (ii) accumulated and communicated to management, including our principal executive officer and principal financial officer, to allow for timely decisions regarding required disclosure.
Previously Identified Material Weakness in Internal Control Over Financial Reporting
As previously disclosed in our 2015 Annual Report on Form 10-K, we did not maintain adequate controls over the valuation of certain assets in the Atlas mergers. Specifically, our review procedures over the development and 15d-15(f) underapplication of inputs, assumptions, and calculations used in cash flow-based fair value measurements associated with business combinations did not operate as designed and at an appropriate level of detail commensurate with our financial reporting requirements.
Remediation Status
We have enhanced our internal control framework applicable to business acquisitions to include formal processes covering the Securities Exchange Actdevelopment, application and review of 1934, as amended) duringinputs, assumptions, and calculations used in cash flow-based value measurements. Cash flow-based fair value measurements are also typically used for asset and goodwill impairment testing. We have not had any events or conditions since December 31, 2015 that have required the use of cash flow-based fair value measurements. As such, neither we nor our external auditors have had the opportunity to test the operating effectiveness of our remediated internal control framework. We will be able to fully test our remediated controls over cash flow-based fair value measurements when we perform our annual goodwill impairment testing for the 2016 reporting cycle, or earlier if another need arises for such value measurements.
57
Changes in Internal Control Over Financial Reporting During the Quarter Ended March 31, 2016
During the three months ended September 30, 2015March 31, 2016, there have not been any changes in our internal control over financial reporting that hashave materially affected, or isare reasonably likely to materially affect, our internal control over financial reporting.
PART II – OTHER INFORMATION
The information required for this item is provided in Note 1615 – Contingencies, under the heading “Legal Proceedings” included in the Notes to Consolidated Financial Statements included under Part I, Item 1 of this Quarterly Report, which is incorporated by reference into this item.
For an in-depth discussion of our risk factors, see “Part I—Item 1A. Risk Factors” inof our 20142015 Annual Report, except for the additional risk factor discussed below. All of these risks and uncertainties could adversely affect our business, financial condition and/or results of operations.
Changes in future business conditions could cause recorded goodwill and property, plant and equipment assets to become further impaired, and our financial condition and results of publicly traded partnershipsoperations could suffer if there is an additional impairment of goodwill or an investmentother intangible assets with indefinite lives, intangible assets with definite lives, or property, plant and equipment assets.
During 2015, global oil and natural gas commodity prices, particularly crude oil, significantly decreased as compared to 2014, and global oil and natural gas commodity prices remained depressed in the first quarter of 2016. This decrease in commodity prices has had, and is expected to continue to have, a negative impact on the demand for our unitsservices and our market capitalization. Should energy industry conditions further deteriorate, there is a possibility that goodwill, intangible assets and property, plant and equipment may be impaired in a future period. Any additional impairment charges that we may take in the future could be subjectmaterial to potential legislative, judicialour financial results. We cannot accurately predict the amount and timing of any impairment of goodwill, intangible assets or administrative changesproperty, plant and differing interpretations, possibly onequipment. For a retroactive basis.
Item 2. Unregistered Sales of our gross income that we are able to treat as qualifying income for the purposesEquity Securities and Use of the qualifying income requirement and modify or revoke existing rulings, including ours.
Recent Sales of Unregistered Securities
None.
Repurchase of Equity by Targa Resources Partners LP or Affiliated Purchasers (1)
Period |
| Total number of units withheld (2) |
|
| Average price per share |
|
| Total number of units purchased as part of publicly announced plans |
|
| Maximum number of units that may yet be purchased under the plan |
| ||||
January 1, 2016 - January 31, 2016 |
|
| 1,289 |
|
|
| 10.65 |
|
|
| — |
|
|
| — |
|
Period | Total number of units withheld (1) | Average price per share | Total number of units purchased as part of publicly announced plans | Maximum number of units that may yet be purchased under the plan | ||||||||||||
July 1, 2015 - July 31, 2015 | 80,562 | 38.89 | - | - | ||||||||||||
August 1, 2015 - August 31, 2015 | 4,367 | 34.50 | - | - | ||||||||||||
September 1, 2015 - September 30, 2015 | 285 | 31.32 | - | - |
(1) | All outstanding treasury units were cancelled as a result of the TRC/TRP Merger. The cancellation resulted in a decrease of $10.3 million to our common units as of March 31, 2016. |
(2) | Represents shares that were withheld by us to satisfy tax withholding obligations of certain of our officers, directors and key employees that arose upon the lapse of restrictions on the equity-settled performance units. |
Item 3. Defaults Upon Senior Securities.
Not applicable.
Item 4. Mine Safety Disclosures.
Not applicable.
58
Not applicable.
59
Description | ||
3.1 | Certificate of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.2 to Targa Resources Partners LP’s Registration Statement on Form S-1 filed November 16, 2006 (File No. 333-138747)). | |
3.2 | Certificate of Formation of Targa Resources GP LLC (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)). | |
3.3 | Second Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 15, 2015 (File No. 001-33303)). | |
3.4 | Limited Liability Company Agreement of Targa Resources GP LLC (incorporated by reference to Exhibit 3.4 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)). | |
4.1 | ||
Specimen Unit Certificate for the Series A Preferred Units (attached as Exhibit B to the Second Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP and incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 15, 2015 (File No. 001-33303)). | ||
31.1* |
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
101.INS* | XBRL Instance Document | |
101.SCH* | XBRL Taxonomy Extension Schema Document | |
101.CAL* | XBRL Taxonomy Extension Calculation Linkbase Document | |
101.DEF* | XBRL Taxonomy Extension Definition Linkbase Document | |
101.LAB* | XBRL Taxonomy Extension Label Linkbase Document | |
101.PRE* | XBRL Taxonomy Extension Presentation Linkbase Document |
* | Filed herewith |
** | Furnished herewith |
+ | Management contract or compensatory plan or arrangement |
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 Partners LP (Registrant) | ||
By: | ||
Targa Resources GP LLC, | ||
its general partner | ||
Date: | By: | /s/ Matthew J. Meloy |
Matthew J. Meloy | ||
Executive Vice President and Chief Financial Officer | ||
(Authorized Officer and Principal Financial Officer) |
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