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UNITED
STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM i10-Q
i☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
(Exact name of registrant as specified in its charter)
iDelaware
i27-3235920
(State
or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
i700 Milam Street, iSuite 1900
iHouston,
iTexasi77002
(Address of principal executive offices) (Zip Code)
(i713)
i375-5000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the
Act:
Title of each class
Trading Symbol
Name of each exchange on which registered
iNone
None
None
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 ☐iNo☒
Note: As of January
1, 2022, the registrant is a voluntary filer not subject to the filing requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934. However, the registrant has filed all reports required pursuant to Sections 13 or 15(d) during the preceding 12 months as if the registrant was subject to such filing requirements.
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). iYes☒No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,”“accelerated filer,”“smaller
reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
☐
Accelerated filer
☐
iNon-accelerated
filer
☒
Smaller reporting company
i☐
Emerging growth company
i☐
If
an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes i☐ No ☒
Indicate the number of shares outstanding of the issuer’s classes of common stock, as of the latest practicable date: Not applicable
As used in this quarterly report, the terms listed below have the following meanings:
Common Industry and Other Terms
ASU
Accounting Standards Update
Bcf
billion cubic feet
Bcf/d
billion
cubic feet per day
Bcf/yr
billion cubic feet per year
Bcfe
billion cubic feet equivalent
DOE
U.S. Department of Energy
EPC
engineering, procurement and construction
FASB
Financial Accounting Standards Board
FERC
Federal
Energy Regulatory Commission
FTA countries
countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
GAAP
generally accepted accounting principles in the United States
Henry Hub
the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
IPM
agreements
integrated production marketing agreements in which the gas producer sells to us gas on a global LNG index price, less a fixed liquefaction fee, shipping and other costs
LIBOR
London Interbank Offered Rate
LNG
liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
MMBtu
million British thermal units; one British
thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
mtpa
million tonnes per annum
non-FTA countries
countries with which the United States does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
SEC
U.S. Securities and Exchange Commission
SPA
LNG sale and
purchase agreement
TBtu
trillion British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
Train
an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
NOTE 1—iNATURE
OF OPERATIONS AND BASIS OF PRESENTATION
We are a Delaware limited liability company formed by CQP. We are a Houston-based company with ione member, Sabine Pass LNG-LP, LLC, an indirect wholly owned subsidiary of CQP. We and SPLNG are each indirect wholly owned subsidiaries of Cheniere Investments, which is a wholly owned subsidiary of CQP, a publicly traded limited
partnership (NYSE MKT: CQP). CQP is a i48.6% owned subsidiary of Cheniere, a Houston-based energy company primarily engaged in LNG-related businesses. Cheniere also owns i100%
of the general partner interest in CQP through ownership in Cheniere Energy Partners GP, LLC.
The natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”) has isix operational Trains, with Train 6 achieving substantial completion on February 4, 2022, for a total production capacity of approximately i30
mtpa of LNG (the “Liquefaction Project”). The Sabine Pass LNG Terminal also has operational regasification facilities owned by SPLNG.
We have increased available liquefaction capacity at our Liquefaction Project as a result of debottlenecking and other optimization projects. We hold a significant land position at the Sabine Pass LNG Terminal, which provides opportunity for further liquefaction capacity expansion. The development of this site or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we make a positive final investment decision.
iBasis
of Presentation
The accompanying unaudited Financial Statements of SPL have been prepared in accordance with GAAP for interim financial information and in accordance with Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements and should be read in conjunction with the Financial Statements and accompanying notes included in our annual report on Form 10-K for the fiscal year ended December 31, 2021.
iWe
are a disregarded entity for federal and state income tax purposes. Our taxable income or loss is included in the federal income tax return of CQP, a publicly traded partnership which indirectly owns us. CQP is not subject to federal or state income taxes, as its partners are taxed individually on their allocable share of CQP’s taxable income. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements.
Results of operations for the three and six months ended June 30, 2022 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2022.
i
Recent
Accounting Standards
ASU 2020-04
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The optional expedients were available to be used upon issuance of this guidance but we have not yet applied the guidance because we have not yet modified any of our existing contracts
for reference rate reform. Once we apply an optional expedient to a modified contract and adopt this standard, the guidance will be applied to all subsequent applicable contract modifications until December 31, 2022, at which time the optional expedients are no longer available.
NOTE 2—iRESTRICTED
CASH AND CASH EQUIVALENTS
Restricted cash and cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal. As of June 30, 2022 and December 31, 2021, we had $i78 million and $i98
million of restricted cash and cash equivalents, respectively.
Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of our debt holders, we are required to deposit all cash received into reserve accounts controlled by the collateral trustee. The usage or withdrawal of such cash is restricted to the payment of liabilities related
to the Liquefaction Project and other restricted payments.
NOTE 3—iTRADE AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES
i
Trade
and other receivables, net of current expected credit losses consisted of the following (in millions):
(1)We
recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction.
We have entered into commodity derivatives consisting of natural gas supply contracts, including those under our IPM agreement, for the operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively
with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”).
We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow or fair value hedging instruments, and changes in fair value are recorded within our Statements of Income to the extent not utilized for the commissioning process, in which case such changes are capitalized.
i
The
following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis (in millions):
We
value our Liquefaction Supply Derivatives using a market or option-based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data.
The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair value including, but not limited to, evaluation of whether the respective market exists from the perspective of market participants as infrastructure is developed.
We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the
valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity and volatility.
The Level 3 fair value measurements of natural gas positions within our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas and international LNG prices. iThe
following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of June 30, 2022 and December 31, 2021:
Net Fair Value Liability (in
millions)
Valuation Approach
Significant Unobservable Input
Range of Significant Unobservable Inputs / Weighted Average (1)
Physical Liquefaction Supply Derivatives
$(i3,456)
Market
approach incorporating present value techniques
Henry Hub basis spread
$(i1.845) - $i0.765
/ $i0.032
Option pricing model
International LNG pricing spread, relative to Henry Hub (2)
i97%
- i604% / i217%
(1)Unobservable
inputs were weighted by the relative fair value of the instruments.
(2)Spread contemplates U.S. dollar-denominated pricing.
Increases or decreases in basis or pricing spreads, in isolation, would decrease or increase, respectively, the fair value of our Physical Liquefaction Supply Derivatives.
Change
in unrealized gains (losses) relating to instruments still held at end of period
$
(i309)
$
i67
$
i63
$
i58
(1)Includes
any assignments during the period.
/
All counterparty derivative contracts provide for the unconditional right of set-off in the event of default. We have elected to report derivative assets and liabilities arising from our derivative contracts with the same counterparty and the unconditional contractual right of set-off on a net basis. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative
instruments are in an asset position. Additionally, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements depending on the position of the derivative. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.
Liquefaction Supply Derivatives
We hold Liquefaction Supply Derivatives which are primarily
indexed to the natural gas market and international LNG indices. The remaining minimum terms of the Physical Liquefaction Supply Derivatives range up to i15 years, some of which commence upon the satisfaction of certain conditions precedent. The terms of the Financial Liquefaction Supply Derivatives range up to approximately itwo
years.
The forward notional amount for our Liquefaction Supply Derivatives was approximately i5,484 TBtu and i5,194
TBtu as of June 30, 2022 and December 31, 2021, respectively, excluding notional amounts associated with extension options that were uncertain to be taken as of June 30, 2022.
i
The following table shows the effect and location of our Liquefaction
Supply Derivatives recorded on our Statements of Income (in millions):
(1)Does
not include the realized value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.
(1)Does
not include collateral posted with counterparties by us of $i9 million and $i7 million, as of June
30, 2022 and December 31, 2021, respectively, which are included in other current assets in our Balance Sheets.
Balance Sheets Presentation
i
The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions) for our derivative instruments that are presented on a net basis on our Balance Sheets:
The indentures governing our senior notes and other agreements underlying our debt contain customary terms and events of default and certain covenants that, among other things, may limit our ability to make certain investments or pay dividends or distributions. We are restricted from making distributions under agreements governing our indebtedness generally until, among other requirements, deposits are made into any required debt service reserve accounts and a historical debt service coverage ratio and
projected debt service coverage ratio of at least i1.25:1.00 is satisfied.
As of June 30, 2022, we were in compliance with all covenants related to our debt agreements.
(1)The
Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.
/
(2)The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.
The estimated fair value of our Working Capital Facility approximates the principal amount outstanding because the interest rates are variable and reflective of market
rates and the debt may be repaid, in full or in part, at any time without penalty.
The
following table shows our contract assets, net of current expected credit losses, which are classified as other current assets and other non-current assets, net on our Balance Sheets (in millions):
The
following table reflects the changes in our contract liabilities to affiliate, which we classify as other non-current liabilities—affiliate on our Balance Sheets (in millions):
Transaction Price Allocated to Future Performance Obligations
Because many of our sales contracts
have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. iThe following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied:
(1)The
weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.
We have elected the following exemptions which omit certain potential future sources of revenue from the table above:
(1)We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.
(2)The table above excludes substantially all variable consideration under our SPAs. We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied
promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Approximately i75%
and i55% of our LNG revenues from contracts included in the table above during the three months ended June 30, 2022 and 2021, respectively, and approximately i72%
and i53% of our LNG revenues from contracts included in the table above during the six months ended June 30, 2022 and 2021, respectively, were related to variable consideration received from customers. Approximately ii100/%
and ii91/%
of our LNG revenues—affiliate from contracts included in the table above during the three and six months ended June 30, 2022 and 2021, respectively, were related to variable consideration received from customers.
We
may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching a final investment decision on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met.
NOTE 10—iRELATED
PARTY TRANSACTIONS
i
Below is a summary of our related party transactions as reported on our Statements of Income (in millions):
Contracts
for Sale and Purchase of Natural Gas and LNG
i35
i2
i47
i6
Total
LNG revenues—affiliate
i1,135
i211
i1,892
i425
LNG
revenues—related party
Natural Gas Transportation and Storage Agreements
i4
i1
i4
i—
Cost
of sales—affiliate
Cheniere Marketing Agreements
i—
i—
i—
i34
Cargo
loading fees under TUA
i12
i11
i25
i22
Contracts
for Sale and Purchase of Natural Gas and LNG
i60
i13
i65
i20
Total
cost of sales—affiliate
i72
i24
i90
i76
Cost
of sales—related party
Natural Gas Transportation and Storage Agreements
i1
i1
i1
i1
Operating
and maintenance expense—affiliate
TUA
i67
i67
i133
i133
Natural
Gas Transportation Agreement
i20
i20
i40
i40
Services
Agreements
i30
i27
i61
i54
LNG
Site Sublease Agreement
i1
i1
i1
i1
Total
operating and maintenance expense—affiliate
i118
i115
i235
i228
Operating
and maintenance expense—related party
Natural Gas Transportation and Storage Agreements
i15
i12
i27
i22
General
and administrative expense—affiliate
Services Agreements
i17
i14
i34
i29
/
As
of June 30, 2022 and December 31, 2021, we had $i478 million and $i232 million, respectively,
of accounts receivable—affiliate under the agreements described below.
LNG Terminal-Related Agreements
Terminal Use Agreements
We have a TUA with SPLNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG. We have reserved approximately i2 Bcf/d of regasification capacity and we are obligated to make monthly capacity payments
to SPLNG aggregating approximately $i250 million per year (the “TUA Fees”), continuing until at least May 2036. We obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA.
CQP has guaranteed our obligations under our TUA. Cargo loading fees incurred under the TUA are recorded as cost of sales—affiliate, except for the portion related to commissioning activities
which is capitalized as LNG terminal construction-in-process.
Cheniere Marketing has an SPA (“Base SPA”) with us to purchase, at Cheniere Marketing’s option, any LNG produced
by us in excess of that required for other customers at a price of i115% of Henry Hub plus $i3.00 per MMBtu of LNG. The Base SPA was subsequently amended to remove certain conditions related to the sale
of LNG from Trains 5 and 6 of the Liquefaction Project and provide that cargoes rejected by Cheniere Marketing under the Base SPA can be sold by us to Cheniere Marketing at a contract price equal to a portion of the estimated net profits from the sale of such cargo.
Cheniere Marketing Master SPA
We have an agreement with Cheniere Marketing that allows us to sell and purchase LNG with Cheniere Marketing by executing and delivering confirmations under this agreement.
Cheniere Marketing Letter Agreements
In May 2022, we and Cheniere Marketing entered into a letter agreement for the sale of up to
i32 TBtu of LNG to be delivered between 2023 and 2025 at a price of i115% of Henry Hub plus $i3.00
per MMBtu.
Cheniere Marketing has letter agreements with us to purchase up to i306 cargoes of LNG to be delivered between 2022 and 2027 at a weighted average price of $i1.95
plus i115% of Henry Hub.
We and Cheniere Marketing had a letter agreement for the sale of up to i30 cargoes of LNG that were delivered in 2021 at a price of
i115% of Henry Hub plus $i0.728 per MMBtu.
Facility Swap Agreement
In
August 2020, we entered into an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be (i) i115% of the applicable natural gas feedstock purchase price or (ii) a free-on-board U.S. Gulf Coast LNG market price, whichever is greater.
Natural
Gas Transportation and Storage Agreements
To ensure we are able to transport adequate natural gas feedstock to the Sabine Pass LNG Terminal, we have transportation agreements to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of CQP, and third party pipeline companies. These agreements with CTPL have a primary term that continues until i20 years from May 2016 and thereafter continue in effect from year to year until terminated by either party upon written notice of ione
year or the term of the agreements, whichever is less. In addition, we have the right to elect to extend the term of the agreements for up to itwo consecutive terms of i10
years. Maximum rates, charges and fees shall be applicable for the entitlements and quantities delivered pursuant to the agreements unless CTPL has advised us that it has agreed otherwise. As of June 30, 2022 and December 31, 2021, we recorded due to affiliates of $i7 million and $i8 million,
respectively, related to this agreement.
We are also party to various natural gas transportation and storage agreements with a related party in the ordinary course of business for the operation of the Liquefaction Project, with initial primary terms of up to i10 years with extension rights. This related party is partially owned by the investment management company that indirectly acquired a portion of CQP’s limited partner interests in September 2020. We recorded accrued liabilities—related party of $i6 million
and $i4 million as of June 30, 2022 and December 31, 2021, respectively, with this related party.
Services Agreements
As of June 30, 2022 and December 31, 2021, we had $i116
million and $i127 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.
Cheniere Investments Information Technology Services Agreement
Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries, including us, receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere Investments according to the cost allocation percentages set forth in the agreement. In addition, Cheniere is entitled to reimbursement for all costs incurred by Cheniere that are necessary to perform the services under the agreement.
Liquefaction O&M Agreement
We have an operation and maintenance agreement (the “Liquefaction O&M Agreement”) with Cheniere Investments, a wholly owned subsidiary of CQP, pursuant to which we receive all necessary services required to operate and maintain the Liquefaction Project. After each Train of the Liquefaction Project is operational, the services include all necessary services required to operate and maintain the Train. Prior to the substantial completion of each Train of the Liquefaction Project, in addition to reimbursement of operating expenses, we are required to pay a monthly fee equal to i0.6%
of the capital expenditures incurred in the previous month. After substantial completion of each Train, for services performed while the Train is operational, we are required to pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $i83,333 (indexed for inflation) for services with respect to the Train through 2042.
Liquefaction MSA
We have a management
services agreement (the “Liquefaction MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the operation of the Liquefaction Project, excluding those matters provided for under the Liquefaction O&M Agreement. The services include, among other services, exercising the day-to-day management of our affairs and business, managing our regulatory matters, managing bank and brokerage accounts and financial books and records of our business and operations, entering into financial derivatives on our behalf and providing contract administration services for all contracts associated with the Liquefaction Project. Prior to the substantial completion of each Train of the Liquefaction Project, we are required to pay a monthly fee equal to i2.4%
of the capital expenditures incurred in the previous month. After substantial completion of each Train, we are required to pay a fixed monthly fee of $i541,667 (indexed for inflation) for services with respect to such Train through 2042.
LNG Site Sublease Agreement
We have agreements with SPLNG to sublease a portion of the Sabine Pass LNG Terminal site for the Liquefaction Project. The
aggregate annual sublease payment is $i1 million. The initial terms of the subleases expire on December 31, 2034, with options to renew for multiple periods of i10 years with similar terms as the
initial terms. The annual sublease payments will be adjusted for inflation every ifive years based on a consumer price index, as defined in the sublease agreements.
Cooperation Agreement
We have a cooperation agreement with SPLNG that allows us to retain and acquire certain rights to access the property and facilities that are owned by SPLNG for the purpose of constructing, modifying and operating the Liquefaction Project. In consideration for access given
to us, we have agreed to transfer to SPLNG title of certain facilities, equipment and modifications, which SPLNG is obligated to operate and maintain. The term of this agreement is consistent with our TUA described above. We did inot convey any assets to SPLNG under this agreement during the three months ended June 30, 2022 and 2021.
Contracts
for Sale and Purchase of Natural Gas and LNG
We have agreements with SPLNG, CTPL and Corpus Christi Liquefaction, LLC (“CCL”) that allow us to sell and purchase natural gas and LNG with each party. Natural gas purchased under these agreements is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. Natural gas sold under these agreements is recorded as LNG revenues—affiliate.
We have a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, we will pay to Cheniere an amount equal to the state and local tax that we would be required to pay if our state and local tax liability were calculated on a separate company basis. To date, there have been ino state
and local tax payments demanded by Cheniere under the tax sharing agreement. The agreement is effective for tax returns due on or after August 2012.
NOTE 11—iCUSTOMER CONCENTRATION
i
The
following table shows external customers with revenues of 10% or greater of total revenues from external customers and external customers with trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total trade and other receivables, net of current expected credit losses from external customers and contract assets, net of current expected credit losses from external customers, respectively:
Percentage
of Total Revenues from External Customers
Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers
Cash
paid during the period for interest on debt, net of amounts capitalized
$
i311
$
i307
/
The
balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate) was $i332 million and $i246 million
as of June 30, 2022 and 2021, respectively.
Novation of IPM Agreement from Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”)
In March 2022, in connection with a prior commitment from Cheniere to collateralize financing for Train 6 of the Liquefaction Project, we and CCL Stage III, formerly a wholly owned direct subsidiary of Cheniere that merged with and into CCL, entered into an agreement to assign to us an IPM agreement to purchase i140,000
MMBtu per day of natural gas at a price based on the Platts Japan Korea Marker (“JKM”), for a term of approximately i15 years beginning in early 2023. The transaction has been accounted for as a transfer between entities under common control, which required us to recognize the obligations assumed at the historical basis of Cheniere. Upon the transfer, which occurred on March 15, 2022, we recognized $i2.7
billion in distributions within our Statements of Member’s Equity (Deficit) based on our assumption of current derivative liabilities and derivative liabilities of $i142 million and $i2.6 billion,
respectively, which represented a non-cash financing activity.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Information Regarding Forward-Looking Statements
This
quarterly report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical or present facts or conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:
•statements that we expect to commence or complete construction of our natural gas liquefaction project, or any expansions or portions thereof, by certain dates, or at all;
•statements regarding
future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries worldwide or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure or demand for and prices related to natural gas, LNG or other hydrocarbon products;
•statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;
•statements regarding our future sources of liquidity and cash requirements;
•statements relating to the construction of our Trains, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms
and provisions of any agreement with any EPC or other contractor, and anticipated costs related thereto;
•statements regarding any SPA or other agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total natural gas liquefaction or storage capacities that are, or may become, subject to contracts;
•statements regarding counterparties to our commercial contracts, construction contracts and other contracts;
•statements
regarding our planned development and construction of additional Trains, including the financing of such Trains;
•statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;
•statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections, or objectives, including anticipated revenues, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;
•statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions;
•statements
regarding the COVID-19 pandemic and its impact on our business and operating results, including any customers not taking delivery of LNG cargoes, the ongoing creditworthiness of our contractual counterparties, any disruptions in our operations or construction of our Trains and the health and safety of Cheniere’s employees, and on our customers, the global economy and the demand for LNG; and
•any other statements that relate to non-historical or future information.
All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,”“will,”“could,”“should,”“achieve,”“anticipate,”“believe,”“contemplate,”“continue,”“estimate,”“expect,”“intend,”“plan,”“potential,”“predict,”“project,”“pursue,”“target,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this quarterly report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this quarterly report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially
from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this quarterly report and in the other reports and other information that we file with the SEC, including those discussed under “Risk Factors” in our annual report on Form 10-K for the fiscal year ended December 31, 2021. All forward-looking statements attributable to us or persons
acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.
Introduction
The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past
performance, current financial condition and outlook for the future.
Our discussion and analysis includes the following subjects:
We are a Delaware limited liability company formed by CQP. We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We aspire to conduct our business in a safe and responsible manner,
delivering a reliable, competitive and integrated source of LNG to our customers.
LNG is natural gas (methane) in liquid form. The LNG we produce is shipped all over the world, turned back into natural gas (called “regasification”) and then transported via pipeline to homes and businesses and used as an energy source that is essential for heating, cooking and other industrial uses. Natural gas is a cleaner-burning, abundant and affordable source of energy. When LNG is converted back to natural gas, it can be used instead of coal, which reduces the amount of pollution traditionally produced from burning fossil fuels, like sulfur dioxide and particulate matter that enters the air we breathe. Additionally, compared to coal, it produces significantly fewer carbon emissions. By liquefying natural gas, we are able to reduce its volume by 600 times so that we can load it onto special
LNG carriers designed to keep the LNG cold and in liquid form for efficient transport overseas.
We own the natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”), one of the largest LNG production facilities in the world, which has six operational Trains, with Train 6 achieving substantial completion on February 4, 2022, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”). The Sabine Pass LNG Terminal also has operational regasification facilities owned and operated by SPLNG.
Our customer arrangements provide us with significant, stable and long-term cash flows. We contract
our anticipated production capacity under SPAs, in which our customers are generally required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, and under IPM agreements, in which the gas producer sells to us gas on a global LNG index price, less a fixed liquefaction fee, shipping and other costs. Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. We have contracted approximately 80% of the total production capacity from the Liquefaction Project with approximately 16 years of weighted average remaining life as of June 30, 2022. In March 2022, the DOE authorized the export of an additional 152.64 Bcf/yr of domestically produced LNG by vessel from the Sabine Pass LNG Terminal through December 31, 2050 to non-FTA countries, that were previously authorized
for FTA countries only. For further discussion of the contracted future cash flows
We remain focused on operational excellence and customer satisfaction. Increasing
demand for LNG has allowed us to expand our liquefaction infrastructure in a financially disciplined manner. We have increased available liquefaction capacity at our Liquefaction Project as a result of debottlenecking and other optimization projects. We hold a significant land position at the Sabine Pass LNG Terminal, which provides opportunity for further liquefaction capacity expansion. The development of this site or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we make a positive final investment decision.
Additionally, we are committed to the responsible and proactive management of our most important environmental, social and governance (“ESG”) impacts, risks and opportunities. In June 2022, Cheniere published its 2021 Corporate
Responsibility (“CR”) report, which details our approach and progress on ESG issues, including Cheniere’s recently announced collaboration with natural gas midstream companies, methane detection technology providers and leading academic institutions to implement quantification, monitoring, reporting and verification of greenhouse gas emissions at natural gas gathering, processing, transmission and storage systems specific to our supply chain, as well as our contributions to energy security during a critical time in history. Additionally, Cheniere commenced providing Cargo Emissions Tags (“CE Tags”) to its customers in June 2022. The CE Tags provide customers with estimated greenhouse gas (“GHG”) emissions data associated with each LNG cargo produced at the Liquefaction Project and are provided for both free-on-board (“FOB”) and delivered ex-ship (“DES”) LNG cargoes. Cheniere’s CR report is available at cheniere.com/our-responsibility/reporting-center. Information
on our website, including the CR report, is not incorporated by reference into this Quarterly Report on Form 10-Q.
Overview of Significant Events
Our significant events since January 1, 2022 and through the filing date of this Form 10-Q include the following:
Strategic
•In June 2022, we entered into an SPA with Chevron
U.S.A Inc. (“Chevron”) to sell Chevron approximately 1.0 mtpa of LNG between 2026 and 2042.
•In February 2022, in connection with a prior commitment from Cheniere to collateralize financing for Train 6 of the Liquefaction Project:
◦Cheniere Marketing entered into agreements to novate to us SPAs entered into with ENN LNG (Singapore) Pte Ltd. and a subsidiary of Glencore plc, with effective dates of January 1, 2023 and February 17, 2022, respectively, aggregating approximately 21 million tonnes of LNG to be delivered between 2023 and 2035.
◦The board of directors of CQP approved our entry into (i) an agreement to novate to us an IPM agreement between
Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”), formerly a wholly owned direct subsidiary of Cheniere (as purchaser) that merged with and into Corpus Christi Liquefaction, LLC, and Tourmaline Oil Marketing Corp., a subsidiary of Tourmaline Oil Corp (as supplier), to purchase 140,000 MMBtu per day of natural gas at a price based on Platts Japan Korea Marker (“JKM”), for a term of approximately 15 years beginning in early 2023 (the “Tourmaline IPM”) and (ii) a FOB SPA with Cheniere Marketing International LLP to sell LNG associated with the natural gas to be supplied under the IPM agreement. The agreement to assign the Tourmaline IPM agreement from CCL Stage III to us was executed and the assignment was effective on March 15, 2022.
Operational
•As
of July 30, 2022, approximately 1,750 cumulative LNG cargoes totaling approximately 120 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.
•On February 4, 2022, substantial completion of Train 6 of the Liquefaction Project was achieved.
The
following charts summarize the total revenues and total LNG volumes loaded from our Liquefaction Project during the six months ended June 30, 2022 and 2021:
(1)
The
six months ended June 30, 2021 excludes eight TBtu under our contracts that were loaded at our affiliate’s facility.
Net income
Our net income was $268 million for the three months ended June 30, 2022, compared to $333 million for the three months ended June 30, 2021 and was $353 million for the six months ended June 30, 2022, compared to $670 million for the six months ended June 30, 2021. The $65 million and $317 million decreases in net income,
respectively, were primarily a result of losses of $431 million and $862 million, respectively, on the derivative liability associated with the Tourmaline IPM agreement following its assignment to us from CCL Stage III in March 2022. See Overview of Significant Events for further discussion of the assignment. The associated losses following the assignment were primarily attributed to our lower credit risk profile relative to that of CCL Stage III, resulting in a higher derivative liability given reduced risk of our own nonperformance and unfavorable shifts in the international forward commodity curve. Partially offsetting the decreased net income during the periods was increased gross margin per MMBtu on LNG delivered, largely due to higher margins on sales indexed to Henry Hub plus a mark up, generally at 115%, as a result of increases in the index, and increased volumes delivered, in part due to substantial completion
and commencement of operations of Train 6 of the Liquefaction Project on February 4, 2022 (the “Train 6 Completion”).
Derivative instruments are utilized to manage our exposure to commodity-related marketing and price risk and are reported at fair value on our Financial Statements. For commodity derivative instruments related to our IPM agreement, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Because the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for
certain of our derivative contracts, use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors, notwithstanding the operational intent to mitigate risk exposure over time.
As described in Overview of Significant Events, during the six months ended June 30, 2022, we entered into an SPA with a counterparty for approximately 1.0 mtpa of LNG to be delivered between 2026 and 2042. We expect our net income or loss in the future to be impacted by the revenues and associated expenses related
to the commencement of this agreement.
(1)The
six months ended June 30, 2021 includes eight TBtu that were loaded at our affiliate’s facility.
Total revenues increased by approximately $2.3 billion and $3.7 billion during the three and six months ended June 30, 2022 from the comparable periods in 2021, respectively, primarily as a result of increased revenues per MMBtu due to appreciation in the Henry Hub index. To a lesser extent, revenues increased as a result of higher volumes of LNG delivered between the periods due to the addition of approximately 5 mtpa of production capacity following Train 6 Completion.
Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against
LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train. During the six months ended June 30, 2022, we realized offsets to LNG terminal costs of $148 million, corresponding to 13 TBtu that were related to the sale of commissioning cargoes from Train 6 of the Liquefaction Project. We did not realize any offsets to LNG terminal costs during the three months ended June 30, 2022 or the three and six months ended June 30, 2021.
Also included in LNG revenues are sales of certain unutilized natural gas procured for the liquefaction process and gains and losses from derivative instruments, which include the realized value associated with a portion of derivative
instruments that settle through physical delivery. We recognized revenues of $67 million and $12 million during the three months ended June 30, 2022 and 2021, respectively, and $121 million and $60 million during the six months ended June 30, 2022 and 2021, respectively, related to these transactions.
Operating costs and expenses
Three
Months Ended June 30,
Six Months Ended June 30,
(in millions)
2022
2021
Variance
2022
2021
Variance
Cost of sales
$
3,144
$
888
$
2,256
$
5,705
$
1,836
$
3,869
Cost
of sales—affiliate
72
24
48
90
76
48
Cost of sales—related party
1
1
—
1
1
—
Operating
and maintenance expense
162
144
18
310
274
18
Operating and maintenance expense—affiliate
118
115
3
235
228
3
Operating
and maintenance expense—related party
15
12
3
27
22
3
General
and administrative expense (recovery)
(3)
1
(4)
(2)
2
(4)
General and administrative expense—affiliate
17
14
3
34
29
3
Depreciation
and amortization expense
134
116
18
264
233
18
Other
—
2
(2)
—
2
(2)
Total
operating costs and expenses
$
3,660
$
1,317
$
2,343
$
6,664
$
2,703
$
3,961
Total
operating costs and expenses increased by $2.3 billion and $4.0 billion during the three and six months ended June 30, 2022 from the comparable periods in 2021, respectively, primarily as a result of increased cost of sales. Cost of sales includes costs incurred directly for the production and delivery of LNG from the Liquefaction Project, to the extent those costs are not utilized for the commissioning process. Cost of sales also includes change in fair value of commodity derivatives to secure natural gas feedstock for the Liquefaction Project, costs associated with the sale of certain unutilized natural gas procured for the liquefaction process, variable transportation and storage costs and other costs to convert natural gas into LNG. Nearly all of the increase in both comparable periods was attributed to third party cost of sales, which increased $2.3 billion and $3.9 billion during the three and six months ended
June 30, 2022, respectively, primarily as a result of increased pricing of natural gas feedstock as a result of higher U.S. natural gas prices and, to a lesser extent, from increased volume of LNG delivered. During the six months ended June 30, 2022, cost of sales additionally included an unfavorable change in the
valuation associated with the Tourmaline IPM agreement that was assigned to us in March 2022, primarily as a result of credit risk as described in Net income
above.
Operating and maintenance expense (including affiliate and related party) primarily includes costs associated with operating and maintaining the Liquefaction Project and also includes service and maintenance, insurance, regulatory costs and other operating costs. During the three and six months ended June 30, 2022, operating and maintenance expense increased from the comparable periods in 2021, primarily due to increased third party service and maintenance contract costs in addition to increased natural gas transportation and storage capacity demand charges following the Train 6 Completion.
Other expense
Three
Months Ended June 30,
Six Months Ended June 30,
(in millions)
2022
2021
Variance
2022
2021
Variance
Interest expense, net of capitalized
interest
$
170
$
158
$
12
$
326
$
318
$
8
Total
other expense
$
170
$
158
$
12
$
326
$
318
$
8
Interest
expense, net of capitalized interest, increased during the three and six months ended June 30, 2022 from the comparable periods in 2021 primarily as a result of the reduction in the portion of total interest costs eligible for capitalization following the Train 6 Completion.
Total interest expense, net of capitalized interest consisted of the following (in millions):
Total interest expense, net of capitalized interest
$
170
$
158
$
326
$
318
Liquidity
and Capital Resources
The following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of restricted cash and cash equivalents and available commitments under our credit facilities. In the long term, we expect to meet our cash requirements using operating cash flows and other future potential sources of liquidity, which may include debt offerings. The table below provides a summary of our available liquidity (in millions).
Restricted cash and cash equivalents designated for the Liquefaction Project
$
78
Available commitments under our working capital revolving credit and letter of credit reimbursement
agreement (the “Working Capital Facility”) (1)
837
Total available liquidity
$
915
(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under the Working Capital Facility as of June
30, 2022. See Note 8—Debt of our Notes to Financial Statements for additional information on the Working Capital Facility and other debt instruments.
Our liquidity position subsequent to June 30, 2022 will be driven by future sources of liquidity and future cash requirements. Future sources of liquidity are expected to be composed of (1) cash receipts from executed contracts, under which we are contractually entitled to future consideration, and (2) additional sources of liquidity, from which we expect to receive cash although the cash is not underpinned by executed contracts. Future
cash requirements are expected to be composed of (1) cash payments under executed contracts, under which we are contractually obligated to make payments, and (2) additional cash requirements, under which we expect to make payments although we are not contractually obligated to make the payments under executed contracts.
The following table summarizes the sources and uses of our restricted cash and cash equivalents (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.
Net
decrease in restricted cash and cash equivalents
$
(20)
$
(32)
Operating Cash Flows
Our
operating cash net inflows during the six months ended June 30, 2022 and 2021 were $1.4 billion and $0.9 billion, respectively. The $464 million increase between the periods was primarily related to increases in cash payments on LNG delivered due to increases in price per MMBtu and volume of LNG delivered, which was partially offset by higher operating cash outflows primarily due to higher natural gas feedstock costs.
Investing Cash Flows
Cash outflows for property, plant and equipment were primarily for the construction costs for Train 6 of the Liquefaction Project, which achieved substantial completion on February 4, 2022. These costs are capitalized as construction-in-process until achievement
of substantial completion.
Financing Cash Flows
During the six months ended June 30, 2022 and 2021, we made distributions of $1.2 billion and $638 million, respectively, to CQP.
Summary of Critical Accounting Estimates
The preparation of Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions
that affect the amounts reported in the Financial Statements and the accompanying notes. There have been no significant changes to our critical accounting estimates from those disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2021.
ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Marketing and Trading Commodity Price Risk
We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Liquefaction Supply Derivatives”). In order to test the sensitivity of the fair value of
the Liquefaction Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location as follows (in millions):
We maintain a set of disclosure controls and procedures
that are designed to ensure that information required to be disclosed by us in the reports filed by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures are effective.
During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting.
We may in the future
be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. Other than discussed below, there have been no material changes to the legal proceedings disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2021.
Louisiana Department of Environmental Quality (“LDEQ”) Matter
Certain of Cheniere’s subsidiaries
are in discussions with the LDEQ to resolve self-reported deviations arising from operation of the Sabine Pass LNG Terminal and the commissioning of the Liquefaction Project, and relating to certain requirements under its Title V Permit. The matter involves deviations self-reported to LDEQ pursuant to the Title V Permit and covering the time period from January 1, 2012 through March 25, 2016. On April 11, 2016, certain of Cheniere’s subsidiaries received a Consolidated Compliance Order and Notice of Potential Penalty (the “Compliance Order”) from LDEQ covering deviations self-reported during that time period. Certain of Cheniere’s subsidiaries
continue to work with LDEQ to resolve the matters identified in the Compliance Order. We do not expect that any ultimate sanction will have a material adverse impact on our financial results.
Pipeline and Hazardous Materials Safety Administration (“PHMSA”) Matter
In February 2018, the PHMSA issued a Corrective Action Order (the “CAO”) to us in connection with a minor LNG leak from one tank and minor vapor release from a second tank at the Sabine Pass LNG Terminal (the “2018 tank incident”). These two tanks have been taken out of operational service while we conduct analysis, repair and remediation. On April 20, 2018, we and PHMSA executed a Consent Agreement and Order (the “Consent Order”) that replaces and supersedes the
CAO. On July 9, 2019, PHMSA and FERC issued a joint letter setting out operating conditions required to be met prior to us returning the tanks to service. In July 2021, PHMSA issued a Notice of Probable Violation (“NOPV”) and Proposed Civil Penalty to us alleging violations of federal pipeline safety regulations relating to the 2018 tank incident and proposing civil penalties totaling $2,214,900. On September 16, 2021, PHMSA issued an Amended NOPV that reduced the proposed penalty to $1,458,200. On October 12, 2021, we responded to the Amended NOPV, electing not to contest the alleged violations in the Amended NOPV and electing to pay the proposed reduced penalty. PHMSA notified us in a letter dated November 9, 2021 that the case was considered “closed.” On
March 9, 2022, PHMSA and FERC issued conditional approval to return one of the two tanks to service. We continue to coordinate with PHMSA and FERC to address the matters relating to the 2018 tank incident, including repair approach and related analysis. We do not expect that the Consent Order and related analysis, repair and remediation or resolution of the NOPV will have a material adverse impact on our financial results or operations.
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.
