NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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 Delaware limited partnership formed in October 2006 by our parent, Targa Resources Corp. (“Targa” or “TRC” or the “Company” or “Parent”). In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our,” “TRP,” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries.
Our common units are wholly owned by TRC and no longer publicly traded as a result of TRC’s acquisition of our outstanding common units that it and its subsidiaries did not already own in 2016.
The 5,000,000 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) that were issued in October 2015 remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.”
Our Operations
We are primarily engaged in the business of:
|
•
|
gathering, compressing, treating, processing, transporting and selling natural gas;
|
|
•
|
transporting, storing, fractionating, treating and selling NGLs and NGL products, including services to LPG exporters; and
|
|
•
|
gathering, storing, terminaling and selling crude oil.
|
See Note 19 – Segment Information for certain financial information regarding our business segments.
The employees supporting our operations are employed by Targa. Our consolidated 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
The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and do not include all information and disclosures required by GAAP. Therefore, this information should be read in conjunction with our consolidated financial statements and notes contained in our Annual Report. The information furnished herein reflects all adjustments that are, in the opinion of management, necessary for a fair statement of the results of the interim periods reported. All significant intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods may have been reclassified to conform to the current year presentation. Operating results for the three months ended March 31, 2019, are not necessarily indicative of the results that may be expected for the year ending December 31, 2019
.
9
Note 3 — Significant Accounting Policies
The accounting policies that we follow are set forth in Note 3 – Significant Accounting Policies of the Notes to Consolidated Financial Statements in our Annual Report. Other than the updates noted below, there were no significant updates or revisions to our accounting policies during the three months ended March 31, 2019.
Recent Accounting Pronouncements
Recently adopted accounting pronouncements
Leases
In February 2016, the
Financial Accounting Standards Board (“FASB”)
issued
Accounting Standards Update (“ASU”)
2016-02,
Leases
(Topic 842). The amendments in this update supersede the leases guidance in Topic 840. We adopted Topic 842 on January 1, 2019 by applying the optional transition method in ASU-2018-11, which permits an entity to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The adoption of Topic 842 did not result in a cumulative effect adjustment to retained earnings on January 1, 2019. As part of the adoption of Topic 842, we recognized a net right-of-use asset of $64.2 million
(net of $0.4 million of lease incentives/deferred rent)
and lease liability of $64.6 million. Other practical expedients we elected include:
|
•
|
The package for transition relief, which among other things, allows us to carry forward the historical lease classification;
|
|
•
|
The land easements transition, which allows us to carry forward our historical accounting treatment for land easements prior to the effective date of the new leases standard and evaluate under Topic 842 only new or modified land easements on or after January 1, 2019;
|
|
•
|
The short-term lease election, which allows us to elect by all asset classes not to record on the balance sheet a lease whose initial term is twelve months or less;
|
|
•
|
The election to not separate non-lease components from lease components for all the asset classes in our current lease portfolio, where Targa is the lessee; and
|
|
•
|
The election to not separate non-lease components from lease components for gathering, processing and storage assets, where Targa is the lessor. Based on our election, we determined the non-lease component in certain of these arrangements is the predominant component, and therefore, account for the arrangements under ASC 606.
|
We recognize the following for all leases (with the exception of short-term leases) at the commencement date:
|
•
|
A
lease liability, which is a lessee’s obligation to make lease payments arising from a lease.
|
|
•
|
A right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term.
|
We determine if an arrangement is or contains a lease at inception. Leases with an initial term of twelve months or less are considered short-term leases, which are excluded from the balance sheet. Right-of-use assets and lease liabilities are recognized at the commencement date based on the present value of future lease payments over the lease term. The right-of-use asset also includes any lease prepayments and excludes lease incentives. As most of the Company’s leases do not provide an implicit interest rate, we use our incremental borrowing rate as the discount rate to compute the present value of our lease liability. The discount rate applied is determined based on information available on the date of adoption for all leases existing as of that date, and on the date of lease commencement for all subsequent leases.
Our lease arrangements may include variable lease payments based on an index or market rate or may be based on performance. For variable lease payments based on an index or market rate, we estimate and apply a rate based on information available at the commencement date. Variable lease payments based on performance are excluded from the calculation of the right-of-use asset and lease liability, and are recognized in our Consolidated Statements of Operations when the contingency underlying such variable lease payments is resolved. Our lease terms may include options to extend or terminate the lease. Such options are included in the measurement of our right-of-use asset and liability, provided we determine that we are reasonably certain to exercise the option.
See Note 11 – Leases for additional details.
10
Recently issued accounting pronouncements not yet adopted
Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract
In August 2018, the FASB issued
ASU
2018-15,
Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract
. The amendments in this update require customers in a cloud computing arrangement that is a service contract to assess related implementation costs for capitalization using the same approach as implementation costs associated with internal-use software. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2019, with early adoption permitted. Entities may apply the amendments using a retrospective or prospective transition method. The amendments will be effective for Targa in the first quarter of 2020. We currently plan to apply the prospective transition method and do not expect a material impact on our Consolidated Financial Statements.
Note 4
—
Divestitures
Subsequent Event
Train 7 Joint Venture
In February 2019, we announced an extension of Grand Prix from Southern Oklahoma to the STACK region of Central Oklahoma where it will connect with the Williams Companies, Inc. (“Williams”) Bluestem Pipeline and link the Conway, Kansas, and Mont Belvieu, Texas, NGL markets. In connection with this project, Williams has committed significant volumes to us that we will transport on Grand Prix and fractionate at our Mont Belvieu facilities. Williams also had an initial option to purchase a 20% equity interest in one of our recently announced 110 MBbl/d fractionation trains (Train 7 or Train 8) in Mont Belvieu. Williams exercised its option to acquire a 20% equity interest in Train 7 and subsequently executed a joint venture agreement with us in the second quarter of 2019. Certain fractionation-related infrastructure for Train 7, including storage caverns and brine handling, will be funded and owned 100% by Targa.
Sale of Interest in Targa Badlands LLC
On April 3, 2019, we closed on the sale of a 45% interest in Targa Badlands LLC, the entity that holds substantially all of our assets in North Dakota, to funds managed by GSO Capital Partners and Blackstone Tactical Opportunities
(collectively, “Blackstone”)
for $1.6 billion in cash. We used the net cash proceeds to repay debt and for general corporate purposes, including funding our growth capital program. We continue to be the operator of Targa Badlands LLC and hold majority governance rights. Future growth capital of Targa Badlands LLC is expected to be funded on a pro rata ownership basis. Targa Badlands LLC will pay a minimum quarterly distribution (“MQD”) to Blackstone and Targa, with Blackstone having a priority right on such MQDs. Additionally, Blackstone’s capital contributions would have a liquidation preference upon a sale of Targa Badlands LLC. We will continue to present Targa Badlands LLC on a consolidated basis in our consolidated financial statements.
Note 5 — Inventories
|
|
March 31, 2019
|
|
|
December 31, 2018
|
|
Commodities
|
|
$
|
176.4
|
|
|
$
|
151.1
|
|
Materials and supplies
|
|
|
21.5
|
|
|
|
13.6
|
|
|
|
$
|
197.9
|
|
|
$
|
164.7
|
|
11
Note 6 — Property, Plant and Equipment and Intangible Assets
|
|
March 31, 2019
|
|
|
December 31, 2018
|
|
|
Estimated Useful Lives (In Years)
|
Gathering systems
|
|
$
|
8,417.2
|
|
|
$
|
7,547.9
|
|
|
5 to 20
|
Processing and fractionation facilities
|
|
|
4,287.4
|
|
|
|
4,001.0
|
|
|
5 to 25
|
Terminaling and storage facilities
|
|
|
1,173.0
|
|
|
|
1,138.7
|
|
|
5 to 25
|
Transportation assets
|
|
|
1,016.8
|
|
|
|
445.1
|
|
|
10 to 25
|
Other property, plant and equipment
|
|
|
398.6
|
|
|
|
334.3
|
|
|
3 to 25
|
Land
|
|
|
149.2
|
|
|
|
144.3
|
|
|
—
|
Construction in progress
|
|
|
2,699.2
|
|
|
|
3,602.5
|
|
|
—
|
Finance lease right-of-use assets
|
|
|
40.9
|
|
|
|
—
|
|
|
|
Property, plant and equipment
|
|
|
18,182.3
|
|
|
|
17,213.8
|
|
|
|
Accumulated depreciation and amortization
|
|
|
(4,479.2
|
)
|
|
|
(4,285.5
|
)
|
|
|
Property, plant and equipment, net
|
|
$
|
13,703.1
|
|
|
$
|
12,928.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible assets
|
|
$
|
2,736.6
|
|
|
$
|
2,736.6
|
|
|
10 to 20
|
Accumulated amortization
|
|
|
(796.4
|
)
|
|
|
(753.4
|
)
|
|
|
Intangible assets, net
|
|
$
|
1,940.2
|
|
|
$
|
1,983.2
|
|
|
|
During the preparation of the Company's consolidated financial statements for the three months ended March 31, 2019, the Company identified an error related to depreciation expense on certain assets that should have been placed in-service during 2018. The Company does not believe this error is material to its previously issued historical consolidated financial statements for any of the periods impacted and accordingly, has not adjusted the historical financial statements. The Company has recorded the cumulative impact of the adjustment in the three months ended March 31, 2019. This adjustment resulted in a one-time $12.5 million overstatement of depreciation expense during the three months ended March 31, 2019.
During the three months ended March 31, 2019 and 2018, depreciation expense was $194.4 million and $152.4 million.
Intangible Assets
Intangible assets consist of customer contracts and customer relationships acquired in prior business combinations. The fair value of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows.
Amortization expense attributable to these assets is recorded over the periods in which we benefit from services provided to customers. We are amortizing these assets over lives ranging from 10 to 20 years
using a method that closely reflects the cash flow pattern underlying their valuation, or the straight-line method, if a reliably determinable pattern of amortization could not be identified.
The estimated annual amortization expense for intangible assets is approximately $171.6 million, $159.4 million, $149.5 million, $141.2 million and $136.0 million for each of the years 2019 through 2023.
The changes in our intangible assets are as follows:
Balance at December 31, 2018
|
|
$
|
1,983.2
|
|
Amortization
|
|
|
(43.0
|
)
|
Balance at March 31, 2019
|
|
$
|
1,940.2
|
|
12
Note 7 – Investments in
Unconsolidated Affiliates
Our investments in unconsolidated affiliates consist of the following:
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•
|
a
38.8% non-operated ownership interest in Gulf Coast Fractionators LP (“GCF”);
|
|
•
|
two non-operated joint ventures in South Texas: a 75% interest in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”), a gas gathering company, and a 50% interest in T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford”), a gas gathering company, (together the “T2 Joint Ventures”);
|
|
•
|
a 50%
operated ownership interest in
Cayenne Pipeline, LLC, a joint venture with American Midstream LLC that owns a 62-mile gas pipeline to an NGL pipeline, which connects the VESCO plant in Venice, Louisiana to the Enterprise Products Operating LLC (“Enterprise”) pipeline at Toca, Louisiana, for delivery to Enterprise’s Norco Fractionator (the “Cayenne Joint Venture”)
;
|
|
•
|
a 25% non-operated ownership intere
st in
Gulf Coast Express Pipeline LLC (“GCX”)
;
|
|
•
|
a
50% operated ownership interest in Little Missouri 4 LLC (the “Little Missouri 4 Joint Venture”), a joint venture to construct a new 200 MMcf/d natural gas processing plant at Targa’s existing Little Missouri facility; and
|
|
•
|
a 10% non-operated ownership interest in
Delaware Basin Residue, LLC
(the “Agua Blanca Joint Venture”)
, a
joint venture with affiliates of First Infrastructure Capital Advisors LLC and Markwest Energy Partners, L.P. in the Agua Blanca pipeline
.
|
Investments in GCF, the Cayenne Joint Venture, GCX and the Agua Blanca Joint Venture are included in the total assets of our Logistics and Marketing segment. Investments in the T2 Joint Ventures and the Little Missouri 4
Joint Venture
are included in the total assets of our Gathering and Processing segment. See Note 19
–
Segment Information for more information regarding our segment assets.
The terms of these joint venture agreements do not afford us the degree of control required for consolidating them in our consolidated financial statements, but do afford us the significant influence required to employ the equity method of accounting
.
The
T2 Joint Ventures were formed to provide services for the benefit of their joint interest owners and have capacity lease agreements with their joint interest owners, which cover costs of operations (excluding depreciation and amortization). On April 1, 2019, we assumed the operatorship of the T2 Joint Ventures.
The following table shows the activity related to our investments in unconsolidated affiliates:
|
|
Balance at
December 31, 2018
|
|
|
Equity Earnings (Loss)
|
|
|
Cash Distributions
|
|
|
Contributions
|
|
|
Balance at
March 31, 2019
|
|
GCF
|
|
$
|
40.3
|
|
|
$
|
4.3
|
|
|
$
|
(2.2
|
)
|
|
$
|
—
|
|
|
$
|
42.4
|
|
T2 LaSalle (1)
|
|
|
49.3
|
|
|
|
(1.5
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
47.8
|
|
T2 Eagle Ford (1)
|
|
|
99.0
|
|
|
|
(2.4
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
96.6
|
|
Cayenne
|
|
|
16.6
|
|
|
|
1.9
|
|
|
|
(2.6
|
)
|
|
|
—
|
|
|
|
15.9
|
|
GCX (2)
|
|
|
211.6
|
|
|
|
0.6
|
|
|
|
—
|
|
|
|
110.4
|
|
|
|
322.6
|
|
Little Missouri 4
|
|
|
67.3
|
|
|
|
—
|
|
|
|
—
|
|
|
|
7.0
|
|
|
|
74.3
|
|
Agua Blanca
|
|
|
6.4
|
|
|
|
(0.1
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
6.3
|
|
Total
|
|
$
|
490.5
|
|
|
$
|
2.8
|
|
|
$
|
(4.8
|
)
|
|
$
|
117.4
|
|
|
$
|
605.9
|
|
(1)
|
As of March 31, 2019, $24.3 million of unamortized excess fair value over the T2 LaSalle and T2 Eagle Ford capital accounts remained. These basis differences, which are attributable to the underlying depreciable tangible gathering assets, are being amortized on a straight-line basis as components of equity earnings over the estimated 20-year useful lives of the underlying assets.
|
(2)
|
Our 25% interest in GCX is owned by Targa GCX Pipeline LLC (“GCX DevCo JV”), of which we own a 20% interest. GCX DevCo JV is accounted for on a consolidated basis in our consolidated financial statements.
|
Note 8 — Accounts
Payable and Accrued Liabilities
|
|
March 31, 2019
|
|
|
December 31, 2018
|
|
Commodities
|
|
$
|
779.3
|
|
|
$
|
721.9
|
|
Other goods and services
|
|
|
379.4
|
|
|
|
474.5
|
|
Interest
|
|
|
91.0
|
|
|
|
79.4
|
|
Permian Acquisition contingent consideration
|
|
|
317.9
|
|
|
|
308.2
|
|
Income and other taxes
|
|
|
40.4
|
|
|
|
45.4
|
|
Other
|
|
|
11.4
|
|
|
|
7.5
|
|
|
|
$
|
1,619.4
|
|
|
$
|
1,636.9
|
|
Accounts payable and accrued liabilities includes $28.9 million and $52.2 million of liabilities to creditors to whom we have issued checks that remained outstanding as of March 31, 2019 and December 31, 2018.
13
Permian Acquisition Contingent Consideration
As a result of a 2017 acquisition of certain gas gathering and processing and crude gathering assets in the Permian Basin (the “Permian Acquisition”), we have included the related contingent consideration in accounts payable and accrued liabilities as of March 31, 2019, and December 31, 2018. The Permian Acquisition contingent consideration represents the second earn-out payment, which will be paid in May 2019, and is derived on a multiple of realized gross margin during the earn-out period from contracts that existed on March 1, 2017, in accordance with the terms of the purchase and sale agreements. The first potential earn-out payment would have occurred in May 2018 and expired with no required payment.
Changes in the value of the contingent consideration liability have been included in Other income (expense).
For the period from December 31, 2018 to March 31, 2019, the value of
the contingent consideration increased
by $9.7 million, primarily attributable to the elimination of discounting and an increase in actual gross margin through the end of the earn-out period.
During the three months ended March 31, 2018, we recognized $56.0 million of expense in Other income (expense) related to the change in fair value of the contingent consideration.
See Note 14 – Fair Value Measurements for additional discussion of the fair value methodology.
Note 9 — Debt Obligations
|
|
March 31, 2019
|
|
|
December 31, 2018
|
|
Current:
|
|
|
|
|
|
|
|
|
Accounts receivable securitization facility, due December 2019 (1)
|
|
$
|
307.6
|
|
|
$
|
280.0
|
|
Senior unsecured notes, 4⅛% fixed rate, due November 2019
|
|
|
—
|
|
|
|
749.4
|
|
|
|
|
307.6
|
|
|
|
1,029.4
|
|
Debt issuance costs, net of amortization
|
|
|
—
|
|
|
|
(1.5
|
)
|
Finance lease liabilities
|
|
|
10.5
|
|
|
|
—
|
|
Current debt obligations
|
|
|
318.1
|
|
|
|
1,027.9
|
|
|
|
|
|
|
|
|
|
|
Long-term:
|
|
|
|
|
|
|
|
|
Senior secured revolving credit facility, variable rate, due June 2023 (2)
|
|
|
670.0
|
|
|
|
700.0
|
|
Senior unsecured notes:
|
|
|
|
|
|
|
|
|
5¼% fixed rate, due May 2023
|
|
|
559.6
|
|
|
|
559.6
|
|
4¼% fixed rate, due November 2023
|
|
|
583.9
|
|
|
|
583.9
|
|
6¾% fixed rate, due March 2024
|
|
|
580.1
|
|
|
|
580.1
|
|
5⅛% fixed rate, due February 2025
|
|
|
500.0
|
|
|
|
500.0
|
|
5⅞% fixed rate, due April 2026
|
|
|
1,000.0
|
|
|
|
1,000.0
|
|
5⅜% fixed rate, due February 2027
|
|
|
500.0
|
|
|
|
500.0
|
|
6½% fixed rate, due July 2027
|
|
|
750.0
|
|
|
|
—
|
|
5% fixed rate, due January 2028
|
|
|
750.0
|
|
|
|
750.0
|
|
6⅞% fixed rate, due January 2029
|
|
|
750.0
|
|
|
|
—
|
|
TPL notes, 4¾% fixed rate, due November 2021 (3)
|
|
|
6.5
|
|
|
|
6.5
|
|
TPL notes, 5⅞% fixed rate, due August 2023 (3)
|
|
|
48.1
|
|
|
|
48.1
|
|
Unamortized premium
|
|
|
0.3
|
|
|
|
0.3
|
|
|
|
|
6,698.5
|
|
|
|
5,228.5
|
|
Debt issuance costs, net of amortization
|
|
|
(42.7
|
)
|
|
|
(31.1
|
)
|
Finance lease liabilities
|
|
|
27.7
|
|
|
|
—
|
|
Long-term debt
|
|
|
6,683.5
|
|
|
|
5,197.4
|
|
Total debt obligations
|
|
$
|
7,001.6
|
|
|
$
|
6,225.3
|
|
Irrevocable standby letters of credit outstanding (2)
|
|
$
|
69.8
|
|
|
$
|
79.5
|
|
|
(1)
|
As of March 31, 2019, we had $337.6 million of qualifying receivables under our $400.0 million accounts receivable securitization facility, resulting in availability of $30.0 million.
|
|
|
(2)
|
As of March 31, 2019, availability under our $2.2 billion senior secured revolving credit facility (“TRP Revolver”) was $1,460.2 million.
|
|
|
(3)
|
“TPL” refers to Targa Pipeline Partners LP.
|
|
The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the three months ended March 31, 2019:
|
|
Range of Interest
Rates Incurred
|
|
|
Weighted Average
Interest Rate
Incurred
|
|
TRP Revolver
|
|
3.8% - 4.3%
|
|
|
4.1%
|
|
Accounts receivable securitization facility
|
|
3.4%
|
|
|
3.4%
|
|
14
Compliance with Debt Covenants
As of March 31, 2019, we were in compliance with the covenants contained in our various debt agreements.
Senior Unsecured Notes Issuances
In January 2019, we issued $750.0 million of 6½% Senior Notes due July 2027 and $750.0 million of 6
⅞% Senior Notes due January 2029, resulting in total net proceeds of $1,487.3 million. The net proceeds from the offerings were used to redeem in full our outstanding 4⅛% Senior Notes due 2019 with the remainder used for general partnership purposes, which included repaying borrowings under our credit facilities.
Debt Extinguishment
In February 2019, we redeemed in full our outstanding 4
⅛% Senior Notes due 2019 at par value plus accrued interest through the redemption date. The redemption resulted in a non-cash loss to write-off $1.4 million of unamortized debt issuance costs, which is included in Gain (loss) from financing activities in the Consolidated Statements of Operations.
Note 10 — Other Long-term Liabilities
Other long-term liabilities are comprised of the following obligations:
|
|
March 31, 2019
|
|
|
December 31, 2018
|
|
Asset retirement obligations
|
|
$
|
63.4
|
|
|
$
|
55.0
|
|
Deferred revenue
|
|
|
174.6
|
|
|
|
175.5
|
|
Operating lease liabilities
|
|
|
17.3
|
|
|
|
—
|
|
Other liabilities
|
|
|
3.0
|
|
|
|
3.3
|
|
Total long-term liabilities
|
|
$
|
258.3
|
|
|
$
|
233.8
|
|
Asset Retirement Obligations
Our asset retirement obligations (“ARO”) primarily relate to certain gas gathering pipelines, processing facilities and transportation assets.
Deferred Revenue
We have certain long-term contractual arrangements for which we have received consideration that we are not yet able to recognize as revenue. The resulting deferred revenue will be recognized once all conditions for revenue recognition have been met.
Deferred revenue includes $129.0 million of payments received from Vitol Americas Corp. (“Vitol”) (formerly known as Noble Americas Corp.), a subsidiary of Vitol US Holding Co., in 2016, 2017, and 2018 as part of an agreement (the “Splitter Agreement”) related to the construction and operation of a crude oil and condensate splitter. In December 2018, Vitol elected to terminate the Splitter Agreement. The Splitter Agreement provides that the first three annual payments are ours if Vitol elects to terminate, which Vitol disputes. The timing of revenue recognition related to the Splitter Agreement deferred revenue is currently dependent upon resolution of the dispute with Vitol. Deferred revenue also includes nonmonetary consideration received in a 2015 amendment to a gas gathering and processing agreement and consideration received for other construction activities of facilities connected to our systems.
The following table shows the changes in deferred revenue:
Balance at December 31, 2018
|
|
$
|
175.5
|
|
Additions
|
|
|
—
|
|
Revenue recognized
|
|
|
(0.9
|
)
|
Balance at March 31, 2019
|
|
$
|
174.6
|
|
15
Note 11
–
Leases
We have non-cancellable operating leases primarily associated with our office facilities, rail assets, land, and storage and terminal assets. We have finance leases primarily associated with our tractors and vehicles. Our leases have remaining lease terms of 1 to 6 years, some of which include options to extend the lease term for up to 10 years.
The balances of right-of-use assets and liabilities of finance leases and operating leases, and their locations on our Consolidated Balance Sheets are as follows:
|
|
Balance Sheet Location
|
|
March 31, 2019
|
|
Right-of-use assets
|
|
|
|
|
|
|
Operating leases, gross
|
|
Other long-term assets
|
|
$
|
25.2
|
|
Finance leases, gross
|
|
Property, plant and equipment
|
|
|
40.9
|
|
|
|
|
|
|
|
|
Lease liabilities
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
Operating leases
|
|
Accounts payable and accrued liabilities
|
|
$
|
6.6
|
|
Finance leases
|
|
Current debt obligations
|
|
|
10.5
|
|
Non-current:
|
|
|
|
|
|
|
Operating leases
|
|
Other long-term liabilities
|
|
|
17.3
|
|
Finance leases
|
|
Long-term debt
|
|
|
27.7
|
|
Operating lease costs and short-term lease costs are included in Operating expenses or General and administrative expense in our Consolidated Statements of Operations, depending on the nature of the leases. Finance lease costs are included in Depreciation and amortization expense and Interest income (expense) in our Consolidated Statements of Operations. The components of lease expense were as follows:
|
|
Three Months Ended March 31, 2019
|
Lease cost
|
|
|
Operating lease cost
|
$
|
1.9
|
Short-term lease cost
|
|
7.6
|
Variable lease cost
|
|
1.3
|
Finance lease cost
|
|
|
Amortization of right-of-use assets
|
|
3.1
|
Interest expense
|
|
0.4
|
Total lease cost
|
$
|
14.3
|
Other supplemental information related to our leases are as follows:
|
|
Three Months Ended March 31, 2019
|
|
Cash paid for amounts included in the measurement of lease liabilities
|
|
|
|
|
Operating cash flows for operating leases
|
|
$
|
1.9
|
|
Operating cash flows for finance leases
|
|
|
0.4
|
|
Financing cash flows for finance leases
|
|
|
2.7
|
|
The weighted-average remaining lease terms for operating leases and finance leases are 4 years and 3 years, respectively. The weighted-average discount rates for operating leases and finance leases are 3.9% and 3.9%, respectively.
The following table presents the maturities of our lease liabilities under non-cancellable leases as of March 31, 2019:
|
|
Operating Leases
|
|
|
Finance Leases
|
|
Future Minimum Lease Payments Beginning After March 31,
|
|
|
|
|
|
|
|
|
2019
|
|
$
|
7.4
|
|
|
$
|
11.8
|
|
2020
|
|
|
5.6
|
|
|
|
11.0
|
|
2021
|
|
|
5.3
|
|
|
|
9.2
|
|
2022
|
|
|
4.2
|
|
|
|
8.2
|
|
2023
|
|
|
2.4
|
|
|
|
1.0
|
|
Thereafter
|
|
|
1.0
|
|
|
|
—
|
|
Total undiscounted cash flows
|
|
|
25.9
|
|
|
|
41.2
|
|
Less imputed interest
|
|
|
(2.0
|
)
|
|
|
(3.0
|
)
|
Total lease liabilities
|
|
$
|
23.9
|
|
|
$
|
38.2
|
|
16
The following table presents future minimum payments under non-cancellable leases as of December 31, 2018:
|
|
Leases
|
|
2019
|
|
$
|
20.5
|
|
2020
|
|
|
17.7
|
|
2021
|
|
|
14.9
|
|
2022
|
|
|
12.6
|
|
2023
|
|
|
6.0
|
|
Thereafter
|
|
|
1.7
|
|
Total payments
|
|
$
|
73.4
|
|
Note 12
— Partnership Units and Related Matters
Distributions
TRC is entitled to receive all Partnership distributions after payment of preferred distributions each quarter.
The following table details the distributions declared and paid by us for the three months ended March 31, 2019:
Three Months Ended
|
|
Date Paid
|
|
Total Distributions
|
|
|
Distributions to
Targa Resources Corp.
|
|
March 31, 2019
|
|
April 5, 2019
|
$
|
|
437.8
|
|
$
|
|
435.0
|
|
December 31, 2018
|
|
February 13, 2019
|
|
|
241.3
|
|
|
|
238.5
|
|
Contributions
All capital contributions to us continue to be allocated 98% to the limited partner and 2% to our general partner; however, no units will be issued for those contributions. During the three months ended March 31, 2019, TRC did not make contributions to us.
Preferred Units
Our Preferred Units rank senior to our common units with respect to distribution rights. Distributions on our 5,000,000 Preferred Units are cumulative from the date of original issue in October 2015 and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of our general partner. Distributions on our Preferred Units are payable out of amounts legally available at a rate equal to 9.0% per annum. On and after November 1, 2020, distributions on our Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%.
We paid $2.8 million of distributions to the holders of Preferred Units (“Preferred Unitholders”) for the three months ended March 31, 2019.
Subsequent Event
In April 2019, the board of directors of our general partner declared a cash distribution of $0.1875 per Preferred Unit, resulting in approximately $0.9 million in distributions that will be paid on May 15, 2019.
17
Note 1
3
— Der
ivative Instru
ments and Hedging Activities
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 entered into derivative instruments to hedge the commodity price risks associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from percent-of-proceeds processing arrangements, (ii) future commodity purchases and sales in our Logistics and Marketing segment and (iii) natural gas transportation basis risk in our Logistics and Marketing segment. The hedge positions associated with (i) and (ii) above will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices and are designated 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 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.
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 record changes in fair value and cash settlements to revenues.
At March 31, 2019, the notional volumes of our commodity derivative contracts were:
Commodity
|
Instrument
|
Unit
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
Natural Gas
|
Swaps
|
MMBtu/d
|
|
175,364
|
|
|
79,930
|
|
|
52,055
|
|
|
-
|
|
|
-
|
|
Natural Gas
|
Basis Swaps
|
MMBtu/d
|
|
111,100
|
|
|
189,119
|
|
|
166,658
|
|
|
150,000
|
|
|
95,000
|
|
NGL
|
Swaps
|
Bbl/d
|
|
17,903
|
|
|
13,267
|
|
|
3,676
|
|
|
-
|
|
|
-
|
|
NGL
|
Futures
|
Bbl/d
|
|
9,735
|
|
|
4,645
|
|
|
-
|
|
|
-
|
|
|
-
|
|
NGL
|
Options
|
Bbl/d
|
|
410
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Condensate
|
Swaps
|
Bbl/d
|
|
4,266
|
|
|
2,390
|
|
|
1,404
|
|
|
-
|
|
|
-
|
|
Condensate
|
Options
|
Bbl/d
|
|
590
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Our derivative contracts are subject to netting arrangements that permit our contracting subsidiaries to net cash settle offsetting asset and liability positions with the same counterparty within the same Targa entity. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements. The following schedules reflect the fair value of our derivative instruments and their location on our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis:
|
|
|
|
Fair Value as of March 31, 2019
|
|
|
Fair Value as of December 31, 2018
|
|
|
|
Balance Sheet
|
|
Derivative
|
|
|
Derivative
|
|
|
Derivative
|
|
|
Derivative
|
|
|
|
Location
|
|
Assets
|
|
|
Liabilities
|
|
|
Assets
|
|
|
Liabilities
|
|
Derivatives designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
Current
|
|
$
|
72.5
|
|
|
$
|
25.2
|
|
|
$
|
112.5
|
|
|
$
|
18.9
|
|
|
|
Long-term
|
|
|
20.4
|
|
|
|
3.1
|
|
|
|
31.6
|
|
|
|
1.5
|
|
Total derivatives designated as hedging instruments
|
|
|
|
$
|
92.9
|
|
|
$
|
28.3
|
|
|
$
|
144.1
|
|
|
$
|
20.4
|
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
Current
|
|
$
|
3.4
|
|
|
$
|
18.1
|
|
|
$
|
2.8
|
|
|
$
|
14.7
|
|
|
|
Long-term
|
|
|
2.7
|
|
|
|
6.3
|
|
|
|
2.5
|
|
|
|
1.6
|
|
Total derivatives not designated as hedging instruments
|
|
|
|
$
|
6.1
|
|
|
$
|
24.4
|
|
|
$
|
5.3
|
|
|
$
|
16.3
|
|
Total current position
|
|
|
|
$
|
75.9
|
|
|
$
|
43.3
|
|
|
$
|
115.3
|
|
|
$
|
33.6
|
|
Total long-term position
|
|
|
|
|
23.1
|
|
|
|
9.4
|
|
|
|
34.1
|
|
|
|
3.1
|
|
Total derivatives
|
|
|
|
$
|
99.0
|
|
|
$
|
52.7
|
|
|
$
|
149.4
|
|
|
$
|
36.7
|
|
18
The pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis is as follows:
|
|
Gross Presentation
|
|
|
Pro Forma Net Presentation
|
|
March 31, 2019
|
Asset
|
|
|
Liability
|
|
|
Collateral
|
|
|
Asset
|
|
|
Liability
|
|
Current Position
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Counterparties with offsetting positions or collateral
|
$
|
69.0
|
|
|
$
|
(42.0
|
)
|
|
$
|
(7.3
|
)
|
|
$
|
43.5
|
|
|
$
|
(23.8
|
)
|
|
Counterparties without offsetting positions - assets
|
|
6.9
|
|
|
|
-
|
|
|
|
-
|
|
|
|
6.9
|
|
|
|
-
|
|
|
Counterparties without offsetting positions - liabilities
|
|
-
|
|
|
|
(1.3
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(1.3
|
)
|
|
|
|
75.9
|
|
|
|
(43.3
|
)
|
|
|
(7.3
|
)
|
|
|
50.4
|
|
|
|
(25.1
|
)
|
Long Term Position
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Counterparties with offsetting positions or collateral
|
|
19.0
|
|
|
|
(9.1
|
)
|
|
|
-
|
|
|
|
13.5
|
|
|
|
(3.6
|
)
|
|
Counterparties without offsetting positions - assets
|
|
4.1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4.1
|
|
|
|
-
|
|
|
Counterparties without offsetting positions - liabilities
|
|
-
|
|
|
|
(0.3
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(0.3
|
)
|
|
|
|
23.1
|
|
|
|
(9.4
|
)
|
|
|
-
|
|
|
|
17.6
|
|
|
|
(3.9
|
)
|
Total Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Counterparties with offsetting positions or collateral
|
|
88.0
|
|
|
|
(51.1
|
)
|
|
|
(7.3
|
)
|
|
|
57.0
|
|
|
|
(27.4
|
)
|
|
Counterparties without offsetting positions - assets
|
|
11.0
|
|
|
|
-
|
|
|
|
-
|
|
|
|
11.0
|
|
|
|
-
|
|
|
Counterparties without offsetting positions - liabilities
|
|
-
|
|
|
|
(1.6
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(1.6
|
)
|
|
|
$
|
99.0
|
|
|
$
|
(52.7
|
)
|
|
$
|
(7.3
|
)
|
|
$
|
68.0
|
|
|
$
|
(29.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Presentation
|
|
|
Pro Forma Net Presentation
|
|
December 31, 2018
|
Asset
|
|
|
Liability
|
|
|
Collateral
|
|
|
Asset
|
|
|
Liability
|
|
Current Position
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Counterparties with offsetting positions or collateral
|
$
|
100.0
|
|
|
$
|
(33.6
|
)
|
|
$
|
(14.2
|
)
|
|
$
|
70.0
|
|
|
$
|
(17.8
|
)
|
|
Counterparties without offsetting positions - assets
|
|
15.3
|
|
|
|
-
|
|
|
|
-
|
|
|
|
15.3
|
|
|
|
-
|
|
|
Counterparties without offsetting positions - liabilities
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
115.3
|
|
|
|
(33.6
|
)
|
|
|
(14.2
|
)
|
|
|
85.3
|
|
|
|
(17.8
|
)
|
Long Term Position
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Counterparties with offsetting positions or collateral
|
|
8.9
|
|
|
|
(3.1
|
)
|
|
|
-
|
|
|
|
5.9
|
|
|
|
(0.1
|
)
|
|
Counterparties without offsetting positions - assets
|
|
25.2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
25.2
|
|
|
|
-
|
|
|
Counterparties without offsetting positions - liabilities
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
34.1
|
|
|
|
(3.1
|
)
|
|
|
-
|
|
|
|
31.1
|
|
|
|
(0.1
|
)
|
Total Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Counterparties with offsetting positions or collateral
|
|
108.9
|
|
|
|
(36.7
|
)
|
|
|
(14.2
|
)
|
|
|
75.9
|
|
|
|
(17.9
|
)
|
|
Counterparties without offsetting positions - assets
|
|
40.5
|
|
|
|
-
|
|
|
|
-
|
|
|
|
40.5
|
|
|
|
-
|
|
|
Counterparties without offsetting positions - liabilities
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
$
|
149.4
|
|
|
$
|
(36.7
|
)
|
|
$
|
(14.2
|
)
|
|
$
|
116.4
|
|
|
$
|
(17.9
|
)
|
Our payment obligations in connection with a majority of these hedging transactions are secured by a first priority lien in the collateral securing the TRP Revolver that ranks equal in right of payment with liens granted in favor of our senior secured lenders. Some of our hedges are futures contracts executed through a broker that clears the hedges through an exchange. We maintain a margin deposit with the broker in an amount sufficient enough to cover the fair value of our open futures positions. The margin deposit is considered collateral, which is located within other current assets on our Consolidated Balance Sheets and is not offset against the fair value of our derivative instruments.
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 $46.3 million as of March 31, 2019. The estimated fair value is net of an adjustment for credit risk based on the default probabilities as indicated by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented. Our futures contracts that are cleared through an exchange are margined daily and do not require any credit adjustment.
The following tables reflect amounts recorded in Other comprehensive income (“OCI”) and amounts reclassified from OCI to revenue for the periods indicated:
|
|
Gain (Loss) Recognized in OCI on
Derivatives (Effective Portion)
|
|
Derivatives in Cash Flow
|
|
Three Months Ended March 31,
|
|
Hedging Relationships
|
|
2019
|
|
|
2018
|
|
Commodity contracts
|
|
$
|
(38.8
|
)
|
|
$
|
64.6
|
|
19
|
|
Gain (Loss) Reclassified from OCI into
Income (Effective Portion)
|
|
|
|
Three Months Ended March 31,
|
|
Location of Gain (Loss)
|
|
2019
|
|
|
2018
|
|
Revenues
|
|
$
|
21.3
|
|
|
$
|
(26.7
|
)
|
Our consolidated earnings are also affected by the 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
|
|
Derivatives Not Designated
|
|
Recognized in Income on
|
|
Three Months Ended March 31,
|
|
as Hedging Instruments
|
|
Derivatives
|
|
2019
|
|
|
2018
|
|
Commodity contracts
|
|
Revenue
|
|
$
|
(9.5
|
)
|
|
$
|
(10.8
|
)
|
Based on valuations as of March 31, 2019, we expect to reclassify commodity hedge-related deferred gains of $64.6 million included in accumulated other comprehensive income into earnings before income taxes through the end of 2021, with $47.3 million of gains to be reclassified over the next twelve months.
See Note 14 – Fair Value Measurements and Note 19 – Segment Information for additional disclosures related to derivative instruments and hedging activities.
20
Note 1
4
— Fair V
alue 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 on our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost on 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, futures, 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.
The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The financial position of these derivatives at March 31, 2019, a net asset position of $46.3 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 liability of $40.1 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 $129.2 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 TRP Revolver and the accounts receivable 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.
|
Contingent consideration liabilities related to business acquisitions are carried at fair value until the end of the related earn-out period.
Fair Value Hierarchy
We categorize the inputs to the fair value measurements of financial assets and liabilities at each balance sheet reporting date 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.
|
21
The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included on our Consolidated Balance Sheets at fair value and (2) supp
lemental fair value disclosures for other financial instruments:
|
|
March 31, 2019
|
|
|
|
|
|
|
|
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)
|
|
$
|
97.2
|
|
|
$
|
97.2
|
|
|
$
|
—
|
|
|
$
|
93.3
|
|
|
$
|
3.9
|
|
Liabilities from commodity derivative contracts (1)
|
|
|
50.9
|
|
|
|
50.9
|
|
|
|
—
|
|
|
|
50.5
|
|
|
|
0.4
|
|
TPL contingent consideration (2)
|
|
|
|
2.4
|
|
|
|
2.4
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2.4
|
|
Financial Instruments Recorded on Our
Consolidated Balance Sheets at Carrying Value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
111.7
|
|
|
|
111.7
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
TRP Revolver
|
|
|
670.0
|
|
|
|
670.0
|
|
|
|
—
|
|
|
|
670.0
|
|
|
|
—
|
|
Senior unsecured notes
|
|
|
6,028.5
|
|
|
|
6,268.9
|
|
|
|
—
|
|
|
|
6,268.9
|
|
|
|
—
|
|
Accounts receivable securitization facility
|
|
|
307.6
|
|
|
|
307.6
|
|
|
|
—
|
|
|
|
307.6
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
|
|
|
|
|
|
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)
|
|
$
|
144.4
|
|
|
$
|
144.4
|
|
|
$
|
—
|
|
|
$
|
137.5
|
|
|
$
|
6.9
|
|
Liabilities from commodity derivative contracts (1)
|
|
|
31.7
|
|
|
|
31.7
|
|
|
|
—
|
|
|
|
31.3
|
|
|
|
0.4
|
|
Permian Acquisition contingent consideration (3)
|
|
|
|
308.2
|
|
|
|
308.2
|
|
|
|
—
|
|
|
|
—
|
|
|
|
308.2
|
|
TPL contingent consideration (2)
|
|
|
2.4
|
|
|
|
2.4
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2.4
|
|
Financial Instruments Recorded on Our
Consolidated Balance Sheets at Carrying Value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
203.3
|
|
|
|
203.3
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
TRP Revolver
|
|
|
700.0
|
|
|
|
700.0
|
|
|
|
—
|
|
|
|
700.0
|
|
|
|
—
|
|
Senior unsecured notes
|
|
|
5,277.9
|
|
|
|
5,088.9
|
|
|
|
—
|
|
|
|
5,088.9
|
|
|
|
—
|
|
Accounts receivable securitization facility
|
|
|
280.0
|
|
|
|
280.0
|
|
|
|
—
|
|
|
|
280.0
|
|
|
|
—
|
|
(1)
|
The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 13– Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes.
|
(2)
|
We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which is carried at fair value.
|
(3)
|
We have a contingent consideration liability related to the Permian Acquisition, which was carried at fair value as of December 31, 2018. See Note 8 – Accounts Payable and Accrued Liabilities.
|
Additional Information Regarding Level 3 Fair Value Measurements Included on 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 or implied volatilities 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 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.
As of March 31, 2019, we had 13 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 (i) the forward natural gas liquids pricing curves, for which a significant portion of the derivative’s term is beyond available forward pricing and (ii) implied volatilities, which are unobservable as a result of inactive natural gas liquids options trading. 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.
22
The fair valu
e of the Permian Acquisition contingent consideration as of December 31, 2018, was determined using a Monte Carlo simulation model. Significant inputs used in the fair value measurement include expected gross margin (calculated in accordance with the terms
of the purchase and sale agreements), term of the earn-out period, risk adjusted discount rate and volatility associated with the underlying assets. The Permian Acquisition contingent consideration earn-out period ended on February 28, 2019. The first ear
n-out payment due in May 2018 expired with no required payment. The second earn-out payment will be paid in
May 2019 and
is
derived
on a multiple of realized gross margin during the earn-out period from contracts that existed on March 1, 2017, in accordanc
e with the terms of the purchase and sale agreements.
As such, the carrying value of the Permian Acquisition contingent consideration as of March 31, 2019, approximates fair value, as with our other accounts payables.
See Note 8 – Accounts Payable and Accr
ued Liabilities
for
additional
discussion of the
Permian Acquisition contingent consideration
.
The fair value of the TPL contingent consideration was determined using a probability-based model measuring the likelihood of meeting certain volumetric measures. The inputs for both models are not observable; therefore, the entire valuations of the contingent considerations are categorized in Level 3. Changes in the fair value of these liabilities are included in Other income (expense) in our Consolidated Statements of Operations.
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)
|
|
|
Consideration
|
|
Balance, December 31, 2018
|
|
$
|
6.5
|
|
|
$
|
(310.6
|
)
|
|
Completion of Permian Acquisition contingent consideration earn-out period
|
|
|
-
|
|
|
|
308.2
|
|
|
Unrealized gain/(loss) included in OCI
|
|
|
(3.1
|
)
|
|
|
-
|
|
Balance, March 31, 2019
|
|
$
|
3.4
|
|
|
$
|
(2.4
|
)
|
Note 15
— 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) until March 2018, 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,
|
|
|
|
2019
|
|
|
2018
|
|
Targa billings of payroll and related costs included in operating expenses
|
|
$
|
54.1
|
|
|
$
|
59.5
|
|
Targa allocation of general and administrative expense
|
|
|
67.8
|
|
|
|
47.3
|
|
Cash distributions to Targa based on general partner and limited partner ownership
|
|
|
238.5
|
|
|
|
225.7
|
|
Cash contributions from Targa related to limited partner ownership (1)
|
|
|
—
|
|
|
|
58.8
|
|
Cash contributions from Targa to maintain its 2% general partner ownership
|
|
|
—
|
|
|
|
1.2
|
|
__________________________________________________________________________________________________________
(1)
|
The cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partner and 2% to general partner. See Note 12 – Partnership Units and Related Matters.
|
23
Note 1
6
– Contingencie
s
Legal Proceedings
We are a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business. We are also a party to various proceedings with governmental environmental agencies in 2019, including but not limited to the Environmental Protection Agency, Texas Commission on Environmental Quality, Oklahoma Department of Environmental Quality, New Mexico Environment Department, Louisiana Department of Environmental Quality and North Dakota Department of Environmental Quality, which assert penalties for alleged violations of environmental regulations, including air emissions, discharges into the environment and reporting deficiencies, related to events that have arisen at certain of our facilities in the ordinary course of our business.
On February 26, 2019, the U.S. Environmental Protection Agency Region 8 and Targa Badlands LLC entered into a Final Order and Consent Agreement in connection with Targa Badlands LLC’s alleged violation of Subpart ZZZZ of the National Emission Standards for Hazardous Air Pollutants at its Junction Compressor Station in McKenzie County, North Dakota. The Consent Agreement imposed a $220,000 civil penalty and requires certain compliance improvements.
Note 17 – Revenue
Fixed consideration allocated to remaining performance obligations
The following table includes the estimated minimum revenue expected to be recognized in the future related to performance obligations that are unsatisfied (or partially unsatisfied) at the end of the reporting period and is comprised of fixed consideration primarily attributable to contracts with minimum volume commitments and for which a guaranteed amount of revenue can be calculated
. These contracts are comprised primarily of gathering and processing, fractionation, export, terminaling and storage agreements.
|
|
2019
|
|
|
2020
|
|
|
2021 and after
|
|
Fixed consideration to be recognized as of March 31, 2019
|
|
$
|
394.3
|
|
|
$
|
463.0
|
|
|
$
|
3,327.5
|
|
In accordance with the optional exemptions that we elected to apply, the amounts presented in the table above exclude variable consideration for which the allocation exception is met and consideration associated with performance obligations of short-term contracts. In addition, consideration from contracts for which we recognize revenue at the amount that we have the right to invoice for services performed is also excluded from the table above, with the exception of any fixed consideration attributable to such contracts. The nature of the performance obligations for which the consideration has been excluded is consistent with the performance obligations described within our revenue recognition accounting policy; the estimated remaining duration of such contracts primarily ranges from 1 to 20 years. In addition, variability exists in the consideration excluded due to the unknown quantity and composition of volumes to be serviced or sold as well as fluctuations in the market price of commodities to be received as consideration or sold over the applicable remaining contract terms. Such variability is resolved at the end of each future month or quarter.
For disclosures related to disaggregated revenue, see Note 19
– Segment Information.
Note 18 — Supple
mental Cash Flow Information
|
Three Months Ended March 31,
|
|
|
2019
|
|
2018
|
|
Cash:
|
|
|
|
|
|
|
Interest paid, net of capitalized interest (1)
|
$
|
61.2
|
|
$
|
39.4
|
|
Income taxes paid, net of refunds
|
|
0.3
|
|
|
0.2
|
|
Non-cash investing activities:
|
|
|
|
|
|
|
Deadstock commodity inventory transferred to property, plant and equipment
|
$
|
17.5
|
|
$
|
1.7
|
|
Impact of capital expenditure accruals on property, plant and equipment
|
|
(38.4
|
)
|
|
(22.3
|
)
|
Transfers from materials and supplies inventory to property, plant and equipment
|
|
1.1
|
|
|
0.4
|
|
Contribution of property, plant and equipment to investments in unconsolidated affiliates
|
|
—
|
|
|
16.0
|
|
Change in ARO liability and property, plant and equipment
|
|
7.4
|
|
|
2.1
|
|
Non-cash balance sheet movements related to acquisition of related party:
|
|
|
|
|
|
|
Intercompany payable
|
$
|
—
|
|
$
|
1.4
|
|
Noncontrolling interest
|
|
—
|
|
|
1.2
|
|
Lease liabilities arising from recognition of right-of-use assets:
|
|
|
|
|
|
|
Operating lease
|
$
|
0.4
|
|
$
|
—
|
|
Finance lease
|
|
1.5
|
|
|
—
|
|
__________________
(1)
|
Interest capitalized on major projects was $18.9 million and $9.6 million for the three months ended March 31, 2019 and 2018.
|
24
Note
19
— Segm
ent Information
We operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business). Our reportable segments include operating segments that have been aggregated based on the nature of the products and services provided.
Our Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota; and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.
Our Logistics and Marketing segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as storing, fractionating, terminaling, transporting and marketing of NGLs and NGL products, including services to LPG exporters; storing and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Marketing s
egment includes the Grand Prix pipeline, which is currently under construction with certain segments of the pipeline currently in operation. The associated assets are generally connected to and supplied in part by our Gathering and Processing segment and, except for the pipeline projects and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.
Other contains the results of commodity derivative activities related to Gathering and Processing hedges of equity volumes that are included in operating margin and mark-to-market gains/losses related to derivative contracts that were not designated as cash 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, 2019
|
|
|
|
Gathering and Processing
|
|
|
Logistics and Marketing
|
|
|
Other
|
|
|
Corporate
and
Eliminations
|
|
|
Total
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities
|
|
$
|
247.6
|
|
|
$
|
1,726.8
|
|
|
$
|
2.1
|
|
|
$
|
—
|
|
|
$
|
1,976.5
|
|
Fees from midstream services
|
|
|
199.9
|
|
|
|
123.0
|
|
|
|
—
|
|
|
|
—
|
|
|
|
322.9
|
|
|
|
|
447.5
|
|
|
|
1,849.8
|
|
|
|
2.1
|
|
|
|
—
|
|
|
|
2,299.4
|
|
Intersegment revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities
|
|
|
822.8
|
|
|
|
38.4
|
|
|
|
—
|
|
|
|
(861.2
|
)
|
|
|
—
|
|
Fees from midstream services
|
|
|
1.9
|
|
|
|
5.5
|
|
|
|
—
|
|
|
|
(7.4
|
)
|
|
|
—
|
|
|
|
|
824.7
|
|
|
|
43.9
|
|
|
|
—
|
|
|
|
(868.6
|
)
|
|
|
—
|
|
Revenues
|
|
$
|
1,272.2
|
|
|
$
|
1,893.7
|
|
|
$
|
2.1
|
|
|
$
|
(868.6
|
)
|
|
$
|
2,299.4
|
|
Operating margin
|
|
$
|
229.0
|
|
|
$
|
152.1
|
|
|
$
|
2.1
|
|
|
$
|
—
|
|
|
$
|
383.2
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets (1)
|
|
$
|
11,713.9
|
|
|
$
|
5,644.9
|
|
|
$
|
87.9
|
|
|
$
|
84.3
|
|
|
$
|
17,531.0
|
|
Goodwill
|
|
$
|
46.6
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
46.6
|
|
Capital expenditures
|
|
$
|
417.8
|
|
|
$
|
470.9
|
|
|
$
|
—
|
|
|
$
|
16.9
|
|
|
$
|
905.6
|
|
__________________________________________________________________________________________
(1)
|
Assets in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver.
|
25
|
|
Three Months Ended March 31, 2018
|
|
|
|
Gathering and Processing
|
|
|
Logistics and Marketing
|
|
|
Other
|
|
|
Corporate
and
Eliminations
|
|
|
Total
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities
|
|
$
|
265.2
|
|
|
$
|
1,926.3
|
|
|
$
|
(17.8
|
)
|
|
$
|
—
|
|
|
$
|
2,173.7
|
|
Fees from midstream services
|
|
|
161.3
|
|
|
|
120.6
|
|
|
|
—
|
|
|
|
—
|
|
|
|
281.9
|
|
|
|
|
426.5
|
|
|
|
2,046.9
|
|
|
|
(17.8
|
)
|
|
|
—
|
|
|
|
2,455.6
|
|
Intersegment revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities
|
|
|
866.5
|
|
|
|
55.7
|
|
|
|
—
|
|
|
|
(922.2
|
)
|
|
|
—
|
|
Fees from midstream services
|
|
|
1.9
|
|
|
|
6.9
|
|
|
|
—
|
|
|
|
(8.8
|
)
|
|
|
—
|
|
|
|
|
868.4
|
|
|
|
62.6
|
|
|
|
—
|
|
|
|
(931.0
|
)
|
|
|
—
|
|
Revenues
|
|
$
|
1,294.9
|
|
|
$
|
2,109.5
|
|
|
$
|
(17.8
|
)
|
|
$
|
(931.0
|
)
|
|
$
|
2,455.6
|
|
Operating margin
|
|
$
|
220.8
|
|
|
$
|
138.4
|
|
|
$
|
(17.8
|
)
|
|
$
|
—
|
|
|
$
|
341.4
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets (1)
|
|
$
|
10,908.5
|
|
|
$
|
3,595.1
|
|
|
$
|
103.0
|
|
|
$
|
121.1
|
|
|
$
|
14,727.7
|
|
Goodwill
|
|
$
|
256.6
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
256.6
|
|
Capital expenditures
|
|
$
|
273.2
|
|
|
$
|
251.0
|
|
|
$
|
—
|
|
|
$
|
33.8
|
|
|
$
|
558.0
|
|
____________________________________________________________________________________________
(1)
|
Assets in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver.
|
The following table shows our consolidated revenues disaggregated by product and service for the periods presented:
|
Three Months Ended March 31,
|
|
|
2019
|
|
|
2018
|
|
Sales of commodities:
|
|
|
|
|
|
|
|
Revenue recognized from contracts with customers:
|
|
|
|
|
|
|
|
Natural gas
|
$
|
411.3
|
|
|
$
|
470.1
|
|
NGL
|
|
1,408.1
|
|
|
|
1,607.3
|
|
Condensate and crude oil
|
|
137.7
|
|
|
|
86.9
|
|
Petroleum products
|
|
7.6
|
|
|
|
48.2
|
|
|
|
1,964.7
|
|
|
|
2,212.5
|
|
Non-customer revenue:
|
|
|
|
|
|
|
|
Derivative activities - Hedge
|
|
21.3
|
|
|
|
(28.0
|
)
|
Derivative activities - Non-hedge (1)
|
|
(9.5
|
)
|
|
|
(10.8
|
)
|
|
|
11.8
|
|
|
|
(38.8
|
)
|
Total sales of commodities
|
|
1,976.5
|
|
|
|
2,173.7
|
|
|
|
|
|
|
|
|
|
Fees from midstream services:
|
|
|
|
|
|
|
|
Revenue recognized from contracts with customers:
|
|
|
|
|
|
|
|
NGL transportation and services
|
|
36.2
|
|
|
|
41.1
|
|
Storage, terminaling and export
|
|
79.6
|
|
|
|
78.2
|
|
Gathering and processing
|
|
194.5
|
|
|
|
152.1
|
|
Other
|
|
12.6
|
|
|
|
10.5
|
|
|
|
|
|
|
|
|
|
Total fees from midstream services
|
|
322.9
|
|
|
|
281.9
|
|
|
|
|
|
|
|
|
|
Total revenues
|
$
|
2,299.4
|
|
|
$
|
2,455.6
|
|
__________________________________________________________________________________________
(1)
|
Represents derivative activities that are not designated as hedging instruments under ASC 815.
|
The following table shows a reconciliation of reportable segment operating margin to income (loss) before income taxes for the periods presented:
|
Three Months Ended March 31,
|
|
|
2019
|
|
|
2018
|
|
Reconciliation of reportable segment operating
margin to income (loss) before income taxes:
|
|
|
|
|
|
|
|
Gathering and Processing operating margin
|
$
|
229.0
|
|
|
$
|
220.8
|
|
Logistics and Marketing operating margin
|
|
152.1
|
|
|
|
138.4
|
|
Other operating margin
|
|
2.1
|
|
|
|
(17.8
|
)
|
Depreciation and amortization expense
|
|
(237.4
|
)
|
|
|
(198.1
|
)
|
General and administrative expense
|
|
(77.7
|
)
|
|
|
(52.6
|
)
|
Interest income (expense), net
|
|
(75.4
|
)
|
|
|
20.2
|
|
Change in contingent considerations
|
|
(9.7
|
)
|
|
|
(56.1
|
)
|
Other, net
|
|
(2.0
|
)
|
|
|
1.2
|
|
Income (loss) before income taxes
|
$
|
(19.0
|
)
|
|
$
|
56.0
|
|
26