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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
i95-4352386
(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
iCommon Stock, $ 0.003 par value
iLNG
iNYSE
American
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. iYes☒ No ☐
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.
iLarge
accelerated filer
☒
Accelerated filer
☐
Non-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 ☒
As of July 27, 2023, the issuer had i240,623,212
shares of Common Stock outstanding.
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
FID
final investment decision
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
SOFR
Secured
Overnight Financing Rate
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
The following diagram depicts our abbreviated legal entity structure as of June 30, 2023, including our ownership of certain subsidiaries, and the references to these entities used in this quarterly report:
Unless the context requires otherwise, references to “Cheniere,” the “Company,”“we,”“us” and “our” refer to Cheniere Energy,
Inc. and its consolidated subsidiaries, including our publicly traded subsidiary, CQP.
Cost (recovery) of sales (excluding items shown separately below)
i912
i5,752
(i627)
i13,088
Operating
and maintenance expense
i487
i419
i931
i808
Selling,
general and administrative expense
i87
i77
i194
i173
Depreciation
and amortization expense
i297
i276
i594
i547
Other
i11
i6
i21
i11
Total
operating costs and expenses
i1,794
i6,530
i1,113
i14,627
Income
from operations
i2,308
i1,477
i10,299
i864
Other
income (expense)
Interest expense, net of capitalized interest
(i291)
(i357)
(i588)
(i706)
Gain
(loss) on modification or extinguishment of debt
(i2)
(i28)
i18
(i46)
Interest
rate derivative gain (loss), net
i—
(i1)
i—
i2
Interest
income
i55
i7
i89
i8
Other
income (expense), net
i—
(i4)
i3
i—
Total
other expense
(i238)
(i383)
(i478)
(i742)
Income
before income taxes and non-controlling interest
i2,070
i1,094
i9,821
i122
Less:
income tax provision (benefit)
i363
i181
i1,679
(i10)
Net
income
i1,707
i913
i8,142
i132
Less:
net income attributable to non-controlling interest
i338
i172
i1,339
i256
Net
income (loss) attributable to common stockholders
$
i1,369
$
i741
$
i6,803
$
(i124)
Net
income (loss) per share attributable to common stockholders—basic (1)
$
i5.65
$
i2.92
$
i27.99
$
(i0.49)
Net
income (loss) per share attributable to common stockholders—diluted (1)
$
i5.61
$
i2.90
$
i27.79
$
(i0.49)
Weighted
average number of common shares outstanding—basic
i242.3
i253.6
i243.1
i253.8
Weighted
average number of common shares outstanding—diluted
i243.8
i255.9
i244.8
i253.8
___________________
(1)Earnings
per share in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.
The accompanying notes are an integral part of these consolidated financial statements.
Trade
and other receivables, net of current expected credit losses
i709
i1,944
Inventory
i404
i826
Current
derivative assets
i93
i120
Margin deposits
i36
i134
Other
current assets
i129
i97
Total current assets
i6,540
i5,608
Property,
plant and equipment, net of accumulated depreciation
i31,821
i31,528
Operating
lease assets
i2,487
i2,625
Derivative
assets
i282
i35
Goodwill
i77
i77
Deferred
tax assets
i36
i864
Other non-current assets, net
i560
i529
Total
assets
$
i41,803
$
i41,266
LIABILITIES
AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities
Accounts payable
$
i100
$
i124
Accrued
liabilities
i1,037
i2,679
Current
debt, net of discount and debt issuance costs
i1,796
i813
Deferred revenue
i130
i234
Current
operating lease liabilities
i598
i616
Current derivative
liabilities
i1,215
i2,301
Other
current liabilities
i37
i28
Total current liabilities
i4,913
i6,795
Long-term
debt, net of premium, discount and debt issuance costs
i23,380
i24,055
Operating
lease liabilities
i1,863
i1,971
Finance
lease liabilities
i483
i494
Derivative
liabilities
i3,740
i7,947
Deferred
tax liabilities
i731
i—
Other non-current
liabilities
i201
i175
Stockholders’
equity (deficit)
Preferred stock: $ii0.0001/
par value, ii5.0/ million shares authorized, iinone/
issued
i—
i—
Common stock: $ii0.003/
par value, ii480.0/ million shares authorized; i277.7
million shares and i276.7 million shares issued at June 30, 2023 and December 31, 2022, respectively
i1
i1
Treasury
stock: i36.8 million shares and i31.2 million shares at June 30, 2023 and December 31, 2022, respectively, at cost
(i3,162)
(i2,342)
Additional
paid-in-capital
i4,363
i4,314
Accumulated
income (deficit)
i1,666
(i4,942)
Total
Cheniere stockholders’ equity (deficit)
i2,868
(i2,969)
Non-controlling
interest
i3,624
i2,798
Total stockholders’ equity (deficit)
i6,492
(i171)
Total
liabilities and stockholders’ equity (deficit)
$
i41,803
$
i41,266
(1)Amounts
presented include balances held by our consolidated variable interest entity (“VIE”), CQP, as further discussed in Note 7—Non-controlling Interest and Variable Interest Entity. As of June 30, 2023, total assets and liabilities of CQP were $i19.3 billion and $i20.5
billion, respectively, including $i1.8 billion of cash and cash equivalents and $i241 million of restricted cash and cash equivalents.
The
accompanying notes are an integral part of these consolidated financial statements.
NOTE 1—iNATURE
OF OPERATIONS AND BASIS OF PRESENTATION
We operate itwo natural gas liquefaction and export facilities located in Cameron Parish, Louisiana at Sabine Pass and near Corpus Christi, Texas (respectively, the “Sabine Pass LNG Terminal” and “Corpus Christi LNG Terminal”).
CQP owns the Sabine Pass LNG Terminal, which has natural gas liquefaction facilities consisting of isix
operational Trains, for a total production capacity of approximately i30 mtpa of LNG (the “SPL Project”). The Sabine Pass LNG Terminal also has operational regasification facilities that include ifive LNG storage tanks, vaporizers and ithree
marine berths. Additionally, the Sabine Pass LNG Terminal includes a i94-mile pipeline owned by CTPL, a subsidiary of CQP, that interconnects our facilities with a number of large interstate and intrastate pipelines. As of June 30, 2023, we owned i100%
of the general partner interest and a i48.6% limited partner interest in CQP.
The Corpus Christi LNG Terminal currently has ithree
operational Trains for a total production capacity of approximately i15 mtpa of LNG, ithree LNG storage tanks and itwo
marine berths. Additionally, we are constructing an expansion of the Corpus Christi LNG Terminal (the “Corpus Christi Stage 3 Project”) for up to iseven midscale Trains with an expected total production capacity of over i10 mtpa of LNG. Through our subsidiary CCP, we also own a i21.5-mile
natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Corpus Christi LNG Terminal and the Corpus Christi Stage 3 Project, the “CCL Project”).
We have increased available liquefaction capacity at the SPL Project and the CCL Project (collectively, the “Liquefaction Projects”) as a result of debottlenecking and other optimization projects. We hold significant land positions at both the Sabine Pass LNG Terminal and the Corpus Christi LNG Terminal which provide opportunity for further liquefaction capacity expansion. In March 2023, certain of our subsidiaries submitted an application with the FERC under the Natural Gas Act for an expansion adjacent
to the CCL Project consisting of itwo midscale Trains with an expected total production capacity of approximately i3 mtpa of LNG. In May 2023, certain subsidiaries of CQP entered the pre-filing review process
with the FERC under the National Environmental Policy Act for an expansion adjacent to the SPL Project consisting of up to ithree Trains with an expected total production capacity of approximately i20 mtpa of LNG (the “SPL Expansion Project”). The development of these sites 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 FID.
i
Basis of Presentation
The accompanying unaudited Consolidated Financial Statements of Cheniere have been prepared in accordance with GAAP for interim financial information and in accordance with Rule
10-01 of Regulation S-X and reflect all normal recurring adjustments which are, in the opinion of management, necessary for a fair statement of the financial results for the interim periods presented. 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 Consolidated Financial Statements and accompanying notes included in our annual report on Form 10-K for the fiscal year ended December 31, 2022.
Results of operations for the three and six months ended June 30, 2023 are not necessarily indicative of the results
of operations that will be realized for the year ending December 31, 2023.
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 contracts expected to arise from the market transition from LIBOR to alternative reference rates. The temporary optional expedients under the standard became effective March 12, 2020 and will be available until December 31, 2024 following a subsequent amendment to the standard.
As further detailed in Note
9—Debt, our existing credit facilities include a variable interest rate indexed to SOFR, incorporated through amendments or replacements of previous credit facilities subsequent to the effective date of ASU
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
2020-04. We elected to apply the optional expedients as applicable
to certain modified or replaced facilities; however, the impact of applying the optional expedients was not material, and the transition to SOFR did not have a material impact on our cash flows.
NOTE 2—iRESTRICTED CASH AND CASH EQUIVALENTS
i
Restricted
cash and cash equivalents consisted of the following (in millions):
Cash
held by our subsidiaries that is restricted to Cheniere
i247
i304
Total
restricted cash and cash equivalents
$
i640
$
i1,134
/
Pursuant
to the accounts agreements entered into with the collateral trustees for the benefit of SPL’s debt holders and CCH’s debt holders, SPL and CCH are required to deposit all cash received into reserve accounts controlled by the collateral trustees. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Projects and other restricted payments. The majority of the cash held by our subsidiaries that is restricted to Cheniere relates to advance funding for operation and construction needs of the Liquefaction Projects.
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 Projects during the testing phase for its construction.
NOTE 6—iDERIVATIVE INSTRUMENTS
We
have entered into the following derivative instruments:
•commodity derivatives consisting of natural gas and power supply contracts, including those under our IPM agreements, for the development, commissioning and operation of the Liquefaction Projects and associated economic hedges (collectively, “Liquefaction Supply Derivatives”);
•LNG derivatives in which we have contractual net settlement and economic hedges on the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (collectively, “LNG Trading Derivatives”); and
•foreign currency exchange (“FX”) contracts
to hedge exposure to currency risk associated with cash flows denominated in currencies other than United States dollar (“FX Derivatives”), associated with both LNG Trading Derivatives and operations in countries outside of the United States.
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 Consolidated Statements of Operations to the extent not utilized for the commissioning process, in which case such changes are capitalized.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
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 and LNG Trading 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. We value our FX Derivatives with a market approach using observable FX rates and other relevant data.
The fair value of our Liquefaction Supply Derivatives and LNG Trading Derivatives are 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 significant portion of our 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 our natural gas positions within our 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 Liquefaction Supply Derivatives as of June 30, 2023:
Net Fair Value Liability
(in millions)
Valuation
Approach
Significant Unobservable Input
Range of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives
$(i4,611)
Market approach incorporating
present value techniques
Henry Hub basis spread
$(i1.733) - $i0.660 / $(i0.054)
Option
pricing model
International LNG pricing spread, relative to Henry Hub (2)
i83% - i484% / i191%
(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 Liquefaction Supply Derivatives.
Realized
and change in fair value gains (losses) included in net income (loss) (1):
Included in cost of sales, existing deals (2)
i635
(i1,407)
i4,518
(i4,482)
Included
in cost of sales, new deals (3)
i3
i—
i9
i—
Purchases
and settlements:
Purchases (4)
i—
i90
i—
(i242)
Settlements
(5)
i175
i278
i780
i298
Transfers
in and/or out of level 3
Transfers out of level 3 (6)
i2
i—
i6
i—
Balance,
end of period
$
(i4,611)
$
(i8,462)
$
(i4,611)
$
(i8,462)
Favorable
(unfavorable) changes in fair value relating to instruments still held at the end of the period
$
i638
$
(i1,407)
$
i4,527
$
(i4,482)
(1)Does
not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to contractually fixed price from trade date multiplied by contractual volume. See settlements line item in this table.
(2)Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period.
(3)Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period.
(4)Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts
acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting period and continuing to exist at the end of the period.
(5)Roll-off in the current period of amounts recognized in our Consolidated Balance Sheets at the end of the previous period due to settlement of the underlying instruments in the current period.
(6)Transferred out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.
/
All existing 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 those 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.
Commodity Derivatives
SPL and CCL hold Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. The terms of the Liquefaction Supply Derivatives range up to approximately i15 years, some of which commence upon the satisfaction of certain events or states of affairs.
Cheniere
Marketing has historically entered into, and may from time to time enter into, LNG transactions that provide for contractual net settlement. Such transactions are accounted for as LNG Trading Derivatives along with financial commodity contracts in the form of swaps or futures. The terms of LNG Trading Derivatives range up to approximately ione year.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
i
The following table shows the notional amounts of our Liquefaction Supply Derivatives and LNG Trading Derivatives (collectively, “Commodity Derivatives”):
(1)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.
(2)Does not include the realized value associated with Liquefaction Supply Derivatives that settle through physical delivery.
/
FX Derivatives
Cheniere Marketing holds FX Derivatives to protect against the volatility in future cash flows attributable to changes in international currency exchange rates. The FX Derivatives economically hedge the foreign currency exposure
arising from cash flows expended for both physical and financial LNG transactions that are denominated in a currency other than the United States dollar. The terms of FX Derivatives range up to approximately ione year.
The total notional amount of our FX Derivatives was $i414
million and $i619 million as of June 30, 2023 and December 31, 2022, respectively.
i
The
following table shows the effect and location of our FX Derivatives recorded on our Consolidated Statements of Operations (in millions):
Gain
(Loss) Recognized in Consolidated Statements of Operations
(1)Does
not include collateral posted with counterparties by us of $i3 million and $i111 million as of June 30, 2023 and December
31, 2022, respectively, which are included in margin deposits on our Consolidated Balance Sheets, and collateral posted by counterparties to us of $i3 million and izero as of June
30, 2023 and December 31, 2022, respectively, which are included in other current liabilities on our Consolidated Balance Sheets.
(2)Does not include collateral posted with counterparties by us of $i33 million and $i23 million,
as of June 30, 2023 and December 31, 2022, respectively, which are included in margin deposits on our Consolidated Balance Sheets, and collateral posted by counterparties to us of $i2 million and izero
as of June 30, 2023 and December 31, 2022, respectively, which are included in other current liabilities on our Consolidated Balance Sheets.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—CONTINUED
(unaudited)
Consolidated 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 Consolidated Balance Sheets:
NOTE 7—iNON-CONTROLLING
INTEREST AND VARIABLE INTEREST ENTITY
CQP is accounted for as a consolidated VIE. We own a i48.6% limited partner interest in CQP in the form of i239.9
million common units, with the remaining non-controlling limited partner interest held by Blackstone Inc., Brookfield Asset Management Inc. and the public. We also own i100% of the general partner interest and the incentive distribution rights in CQP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
i
The following table presents the summarized assets and liabilities (in millions) of CQP, which are included in our Consolidated Balance Sheets. The assets in the table below may only be used to settle obligations of CQP. In addition, there is no recourse
to us for the consolidated VIE’s liabilities. The assets and liabilities in the table below include third party assets and liabilities of CQP only and exclude intercompany balances between CQP and Cheniere that eliminate in the Consolidated Financial Statements of Cheniere.
Working
capital revolving credit and letter of credit reimbursement agreement (the “SPL Working Capital Facility”)
i—
i—
Revolving
credit and guaranty agreement (the “SPL Revolving Credit Facility”)
i—
i—
Total
debt - SPL
i11,932
i12,132
CQP:
Senior
Notes:
i4.500% due 2029
i1,500
i1,500
i4.000%
due 2031
i1,500
i1,500
i3.25%
due 2032
i1,200
i1,200
i5.95%
due 2033 (the “2033 CQP Senior Notes”)
i1,400
i—
Total
CQP Senior Notes
i5,600
i4,200
Credit
facilities (the “CQP Credit Facilities”)
i—
i—
Revolving
credit and guaranty agreement (the “CQP Revolving Credit Facility”)
i—
i—
Total
debt - CQP
i5,600
i4,200
CCH:
Senior
Secured Notes:
i7.000% due 2024 (the “2024 CCH Senior Notes”)
i—
i498
i5.875%
due 2025
i1,491
i1,491
i5.125%
due 2027
i1,201
i1,271
i3.700%
due 2029
i1,125
i1,361
i3.788%
weighted average rate due 2039
i2,539
i2,633
Total
CCH Senior Secured Notes
i6,356
i7,254
Term
loan facility agreement (the “CCH Credit Facility”)
i—
i—
Working
capital facility agreement (the “CCH Working Capital Facility”) (2)
i—
i—
Total
debt - CCH
i6,356
i7,254
Cheniere:
i4.625%
Senior Notes due 2028
i1,500
i1,500
Revolving
credit agreement (the “Cheniere Revolving Credit Facility”)
i—
i—
Total
debt - Cheniere
i1,500
i1,500
Cheniere
Marketing: trade finance facilities (2)
i—
i—
Total
debt
i25,388
i25,086
Current
portion of long-term debt
(i1,796)
(i813)
Long-term
portion of unamortized premium, discount and debt issuance costs, net
(i212)
(i218)
Total
long-term debt, net of premium, discount and debt issuance costs
$
i23,380
$
i24,055
(1)In
July 2023, SPL redeemed $i1.4 billion aggregate principal amount outstanding of the 2024 SPL Senior Notes using contributed proceeds from the 2033 CQP Senior Notes and cash on hand.
(2)These debt instruments are classified as short-term debt as we are required to reduce the aggregate outstanding principal amount of the CCH Working Capital Facility to zero for a period of five consecutive business days at least once each year, and the borrowings under the Cheniere Marketing trade finance facilities are required to be repaid within 90 days.
(1)In June 2023, CQP and SPL refinanced and replaced the CQP Credit Facilities and the SPL Working Capital Facility with the CQP Revolving Credit Facility and the SPL Revolving Credit Facility, respectively, resulting in extended maturity dates, revised borrowing capacities, reduced rate of interest and commitment fees applicable thereunder and certain other changes to terms and conditions.
(2)In June 2023, we amended the Cheniere Revolving Credit Facility to update the indexed interest rate to SOFR.
(3)The margin on the
interest rate and the commitment fees is subject to change based on the applicable entity’s credit rating.
(4)In April 2023, the commitment fees for the Cheniere Revolving Credit Facility were reduced as a result of achieving certain ESG metrics.
(5)The CCH Credit Facility matures the earlier of iJune 15, 2029 or itwo
years after the substantial completion of the last Train of the Corpus Christi Stage 3 Project.
/
The refinancing and the replacement of the CQP Credit Facilities and the SPL Working Capital Facility resulted in an aggregate of $ii1/ million
of debt extinguishment and modification costs.
Restrictive Debt Covenants
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 us, our subsidiaries’ and its restricted subsidiaries’ ability to make certain investments or pay dividends or distributions. SPL and CCH are restricted from making distributions under agreements governing their respective indebtedness generally until, among other requirements, appropriate
reserves have been established for debt service using cash or letters of credit 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, 2023, each of our issuers was in compliance with all covenants related to their respective debt agreements.
(1)As
of both June 30, 2023 and December 31, 2022, $ii3.0/ billion
of the fair value of our senior notes included an illiquidity adjustment, which qualified as a Level 3 fair value measurement. The remainder of our senior notes are classified as Level 2, based on prices derived from trades or indicative bids of the instruments or instruments with similar terms, maturities and credit standing.
/
The estimated fair value of our credit facilities 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.
NOTE 10—iLEASES
Our
leased assets consist primarily of LNG vessels leased under time charters (“vessel charters”) and additionally include tug vessels, office space and facilities and land sites. All of our leases are classified as operating leases except for certain of our vessel charters and tug vessels, which are classified as finance leases.
i
The following table shows the classification and location of our right-of-use assets and lease liabilities on our Consolidated Balance Sheets (in millions):
June
30,
December 31,
Consolidated Balance Sheets Location
2023
2022
Right-of-use assets—Operating
Operating lease assets
$
i2,487
$
i2,625
Right-of-use
assets—Financing
Property, plant and equipment, net of accumulated depreciation
(1)Presented
in cost of sales, operating and maintenance expense or selling, general and administrative expense consistent with the use of the asset under lease.
i
Future annual minimum lease payments for operating and finance leases as of June 30, 2023 are as follows (in millions):
Years
Ending December 31,
Operating Leases
Finance Leases
2023
$
i338
$
i32
2024
i674
i66
2025
i554
i71
2026
i421
i75
2027
i324
i77
Thereafter
i524
i427
Total
lease payments (1)
i2,835
i748
Less:
Interest
(i374)
(i233)
Present
value of lease liabilities
$
i2,461
$
i515
(1)Does
not include approximately $i4.4 billion of legally binding minimum payments primarily for vessel charters executed as of June 30, 2023, but will commence in future periods with fixed minimum lease terms of up to i15
years.
/
i
The following table shows the weighted-average remaining lease term and the weighted-average discount rate for our operating leases and finance leases:
(1)The
weighted average discount rate is impacted by certain finance leases that commenced prior to the adoption of the current leasing standard under GAAP. In accordance with previous accounting guidance, the implied rate is based on the fair value of the underlying assets.
Cash
paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases
$
i359
$
i324
Operating
cash flows from finance leases
i18
i5
Financing
cash flows from finance leases
i13
i—
Right-of-use
assets obtained in exchange for operating lease liabilities
i177
i433
Right-of-use
assets obtained in exchange for finance lease liabilities
i5
i—
LNG
Vessel Subcharters
We sublease certain LNG vessels under charter to third parties while retaining our existing obligation to the original lessor. All of our sublease arrangements have been assessed as operating leases. iThe following table shows the sublease income recognized in other revenues on our Consolidated Statements of Operations (in millions):
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 Consolidated Balance Sheets (in millions):
Contract
assets, net of current expected credit losses
$
i196
$
i186
/
i
The
following table reflects the changes in our contract liabilities, which we classify as deferred revenue and other non-current liabilities on our Consolidated 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 and TUAs. 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 the underlying variable index, primarily 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. Additionally, we have excluded variable consideration related to contracts where there is uncertainty that one or both of the parties will achieve certain milestones. Approximately i64% and i74%
of our LNG revenues from contracts included in the table above during the three months ended June 30, 2023 and 2022, respectively, and approximately i73% and i70%
of our LNG revenues from contracts included in the table above during the six months ended June 30, 2023 and 2022, respectively, were related to variable consideration received from customers. During the three and six months ended June 30, 2023, approximately ii7/%
of our regasification revenues were related to variable consideration received from customers and during the three and six months ended June 30, 2022, approximately ii6/%,
of our regasification revenues were related to variable consideration received from customers.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones
such as reaching FID 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 12—iRELATED
PARTY TRANSACTIONS
i
Below is a summary of our related party transactions, all in the ordinary course of business, as reported on our Consolidated Statements of Operations (in millions):
Natural
Gas Transportation and Storage Agreements with a related party through Brookfield Asset Management, Inc. (“Brookfield”) (1)
$
i—
$
i4
$
i—
$
i4
Other
revenues
Operation and Maintenance Services Agreements with Midship Pipeline Company, LLC (“Midship Pipeline”) (2)
i2
i2
i5
i4
Cost
of sales
Natural Gas Transportation and Storage Agreements with a related party through Brookfield (1)
i—
i1
i—
i1
Operating
and maintenance expense
Natural Gas Transportation and Storage Agreements with Midship Pipeline (2)
i2
i3
i4
i5
Natural
Gas Transportation and Storage Agreements with a related party through Brookfield (1)
i14
i15
i30
i27
(1)This
related party is partially owned by Brookfield, who indirectly owns a portion of CQP’s limited partner interests.
(2)Midship Pipeline is a subsidiary of Midship Holdings, LLC, which we recognize as an equity method investment.
Below is a summary of our related party balances, all in the ordinary course of business, as reported on our Consolidated Balance Sheets (in millions):
Trade and other receivables, net of current expected credit losses
$
i2
$
i1
Accrued
liabilities
i5
i1
/
NOTE 13—iINCOME
TAXES
We recorded an income tax provision of $i363 million and $i1.7 billion during the three and six months ended June 30, 2023,
respectively, and an income tax provision (benefit) of $i181 million and $(i10) million for the same periods of 2022, which was calculated using the annual effective tax rate method.
Our effective tax rate
was i17.5% and i17.1% for the three and six months ended June 30, 2023, respectively, as compared to i16.5%
and(i8.2)% for the same periods of 2022. The effective tax rate for the periods was lower than the statutory tax rate of i21% primarily
due to CQP income that is not taxable to us. The effective tax rate for the six months ended June 30, 2022 was also impacted by discrete tax benefits primarily related to stock-based compensation awards.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
We are not subject to the i15%
corporate alternative minimum tax (“CAMT”) in 2023 based on enacted law and regulatory guidance; however, our CAMT status for 2023 could change in the future, depending on new regulations or regulatory guidance issued by the U.S. Department of the Treasury.
NOTE 14—iNET INCOME (LOSS) PER SHARE ATTRIBUTABLE TO COMMON STOCKHOLDERS
i
The
following table reconciles basic and diluted weighted average common shares outstanding and common stock dividends declared (in millions, except per share data):
Net income (loss) attributable to common stockholders
$
i1,369
$
i741
$
i6,803
$
(i124)
Weighted
average common shares outstanding:
Basic
i242.3
i253.6
i243.1
i253.8
Dilutive
unvested stock
i1.5
i2.3
i1.7
i—
Diluted
i243.8
i255.9
i244.8
i253.8
Net
income (loss) per share attributable to common stockholders—basic (1)
$
i5.65
$
i2.92
$
i27.99
$
(i0.49)
Net
income (loss) per share attributable to common stockholders—diluted (1)
$
i5.61
$
i2.90
$
i27.79
$
(i0.49)
Dividends
paid per common share
$
i0.395
$
i0.33
$
i0.790
$
i0.66
(1)Earnings
per share in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.
/
On July 28, 2023, we declared a quarterly dividend of $i0.395 per share of common stock that is payable on August 16, 2023 to stockholders
of record as of the close of business on August 9, 2023.
i
Potentially dilutive securities that were not included in the diluted net income (loss) per share computations because their effects would have been anti-dilutive were as follows (in millions):
4.25%
Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”) (2)
i—
i—
i—
i0.3
Total
potentially dilutive common shares
i—
i—
i—
i2.4
(1)Includes
the impact of unvested shares containing performance conditions to the extent that the underlying performance conditions are satisfied based on actual results as of the respective dates.
/
(2)The 2045 Cheniere Convertible Senior Notes were redeemed or converted in cash on January 5, 2022. However, the adoption of ASU 2020-06 on January 1, 2022 required a presumption of share settlement for the purpose of calculating the impact to diluted earnings per share during the period the notes were outstanding in 2022. Such impact was anti-dilutive as a result of the reported
net loss attributable to common stockholders during the 2022 period.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
NOTE 15—iSHARE
REPURCHASE PROGRAMS
On September 7, 2021, our board of directors (our “Board”) authorized a reset in the previously existing share repurchase program to $i1.0 billion, inclusive of any amounts remaining under the previous authorization as of September 30, 2021, for an additional ithree
years beginning on October 1, 2021. On September 12, 2022, our Board authorized an increase in the existing share repurchase program by $i4.0 billion for an additional ithree
years, beginning on October 1, 2022. iThe following table presents information with respect to common stock repurchased under our share repurchase program (in millions, except per share data):
(1)Amount
excludes associated commission fees and excise taxes incurred, which are excluded costs under the repurchase program.
As of June 30, 2023, we had approximately $i2.8 billion remaining under our share repurchase program.
NOTE 16—iCUSTOMER
CONCENTRATION
i
The concentration of our customer credit risk in excess of 10% of total revenues and/or trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses was as follows:
Percentage
of Total Revenues from External Customers
Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers
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 proposed LNG terminals, liquefaction facilities, pipeline facilities or other projects, 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 relating to Cheniere’s capital deployment, including intent, ability, extent, and timing of capital expenditures, debt repayment, dividends, share repurchases and execution on the capital allocation plan;
•statements
regarding our future sources of liquidity and cash requirements;
•statements relating to the construction of our Trains and pipelines, 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 LNG regasification, 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 or pipelines, including the financing of such Trains or pipelines;
•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 our anticipated LNG and natural gas marketing activities; 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, 2022. 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 Consolidated 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:
Cheniere, a Delaware corporation, is a Houston-based energy infrastructure company primarily engaged in LNG-related businesses. 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, other industrial uses and back up for intermittent energy sources. 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 are the largest producer of LNG in the United States and the second largest LNG operator globally, based on the total production capacity of our liquefaction facilities, which totals approximately 45 mtpa as of June 30, 2023.
We own and operate a 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, through our ownership interest in and management agreements with CQP, which is a publicly traded limited partnership
that we formed in 2007. As of June 30, 2023, we owned 100% of the general partner interest and a 48.6% limited partner interest in CQP. The Sabine Pass LNG Terminal has six operational Trains, for a total production capacity of approximately 30 mtpa of LNG (the “SPL Project”). The Sabine Pass LNG Terminal also has three marine berths, two of which can accommodate vessels with nominal capacity of up to 266,000 cubic meters and the third berth which can accommodate vessels with nominal capacity of up to 200,000 cubic meters, operational regasification facilities that include five LNG storage tanks with aggregate capacity of approximately 17 Bcfe and vaporizers with regasification capacity of approximately 4 Bcf/d. The Sabine Pass LNG Terminal also includes a 94-mile pipeline owned by CTPL, a subsidiary of CQP, that interconnects our facilities to several interstate and intrastate pipelines (the “Creole Trail
Pipeline”).
We also own and operate a natural gas liquefaction and export facility located near Corpus Christi, Texas (the “Corpus Christi LNG Terminal”) through CCL, which has natural gas liquefaction facilities consisting of three operational Trains for a total production capacity of approximately 15 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. Additionally, we are constructing an expansion of the Corpus Christi LNG Terminal (the “Corpus Christi Stage 3 Project”)
for up to seven midscale Trains with an expected total production capacity of over 10 mtpa of LNG. In June 2022, our board of directors (our “Board”) made a positive FID with respect to the Corpus Christi Stage 3 Project and issued a full notice to proceed with construction to Bechtel Energy Inc. (“Bechtel”) effective June 16, 2022. We also own and operate through CCP a 21.5-mile natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Corpus Christi LNG Terminal and the Corpus Christi Stage 3 Project, the “CCL Project”).
Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. We have contracted
substantially all of 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 natural gas to us on a global LNG index price, less a fixed liquefaction fee, shipping and other costs. Through our SPAs and IPM agreements, we have contracted approximately 95% of the total anticipated production from the SPL Project and the CCL Project (collectively, the “Liquefaction Projects”) through the mid-2030s, excluding contracts executed to support additional liquefaction capacity beyond what is currently in construction or operation. Excluding contracts with terms less
than 10 years and contracts executed to support additional liquefaction capacity beyond what is currently in construction or operation, our SPAs and IPM agreements had approximately 16 years of weighted average remaining life as of June 30, 2023. We also market and sell LNG produced by the Liquefaction Projects that is not contracted by CCL or SPL through our integrated marketing function. The majority of our contracts are fixed-priced, long-term SPAs consisting of a fixed fee per MMBtu of LNG plus a variable fee per MMBtu of LNG, with the variable fees generally structured to cover the cost of natural gas purchases and transportation and liquefaction fuel to produce LNG, thus limiting our exposure to fluctuations in U.S. natural gas prices. We
continue to grow our portfolio of SPA and IPM agreements, and we believe that continued global demand for natural gas and LNG will provide a foundation for additional growth in our portfolio of customer contracts in the future.
We remain focused on safety, 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 Projects as a result of debottlenecking and other optimization projects. We hold significant land positions at both the Sabine Pass LNG Terminal and the Corpus Christi LNG Terminal, which provide opportunity for further liquefaction capacity expansion. In March 2023, certain of our subsidiaries
submitted an application with the FERC under the Natural Gas Act (“NGA”) for an expansion adjacent to the CCL Project consisting of two midscale Trains with an expected total production capacity of approximately 3 mtpa of LNG (the “CCL Midscale Trains 8 & 9 Project”). Additionally, in May 2023, certain subsidiaries of CQP entered the pre-filing review process with the FERC under the National Environmental Policy Act (“NEPA”) for an expansion adjacent to the SPL Project consisting of up to three Trains with an expected total production capacity of approximately 20 mtpa of LNG (the “SPL Expansion Project”). The development of the CCL Midscale Trains 8 & 9 Project, the SPL Expansion Project 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 FID.
Additionally, we are committed to the responsible and proactive management of our most important environmental, social and governance (“ESG”) impacts, risks and opportunities. In 2022, we published Acting Today, Securing Tomorrow, our third Corporate Responsibility (“CR”) report, which details our approach and progress on ESG issues, including our collaboration with natural gas midstream companies, technology providers and leading academic institutions on life-cycle assessment (“LCA”) models, quantification, monitoring, reporting and verification (“QMRV”) of greenhouse gas emissions and other research and development projects. We also co-founded and sponsored the Energy Emissions Modeling and Data Lab (“EEMDL”), a multidisciplinary research and
education initiative led by the University of Texas at Austin in collaboration with Colorado State University and the Colorado School of Mines. In addition, we commenced providing Cargo Emissions Tags (“CE Tags”) to our long-term customers in June 2022 and joined the Oil and Gas Methane Partnership (“OGMP”) 2.0, the United Nations Environment Programme’s (“UNEP”) flagship oil and gas methane emissions reporting and mitigation initiative, in October 2022. Our 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.
Our significant events since January 1, 2023 and through the filing date of this Form 10-Q include the following:
Strategic
•Cheniere Marketing entered into long-term SPAs with ENN LNG (Singapore) Pte. Ltd., Equinor ASA and Korea Southern Power Co. Ltd. with estimated volumes aggregating up to approximately 76 million tonnes of LNG and expected deliveries between 2026 and 2049. Approximately 43 million tonnes is subject to Cheniere making a positive FID on the first train of the SPL Expansion Project. Each of these SPAs permit
Cheniere Marketing to assign or novate the agreement to certain affiliates at a later date.
•In May 2023, certain subsidiaries of CQP entered the pre-filing review process with the FERC under the NEPA for the SPL Expansion Project, and in April 2023, one of our subsidiaries executed a contract with Bechtel to provide the front end engineering and design work on the project.
•In April 2023, certain of our subsidiaries filed an application with the DOE with respect to the CCL Midscale
Trains 8 & 9 Project, requesting authorization to export LNG to FTA countries and non-FTA countries.
•In March 2023, certain of our subsidiaries submitted an application with the FERC under the NGA for the CCL Midscale Trains 8 & 9 Project.
•On January 2, 2023, Corey Grindal, formerly Executive Vice President, Worldwide Trading, was promoted to Executive Vice President and Chief Operating Officer of the Company.
Operational
•As
of July 27, 2023, over 2,900 cumulative LNG cargoes totaling approximately 200 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects.
Financial
•In July 2023, Fitch Ratings upgraded its issuer credit rating of CCH from BBB- to BBB with a stable outlook.
•In June 2023, CQP entered into a $1.0 billion Senior Unsecured Revolving Credit and Guaranty Agreement (the “CQP Revolving Credit Facility”), and SPL entered into a $1.0 billion Senior Secured Revolving Credit and Guaranty Agreement (the “SPL Revolving Credit Facility”). The CQP Revolving Credit Facility and SPL Revolving Credit Facility each refinanced and replaced
the respective existing credit facilities to, among other things, (1) extend the maturity date thereunder, (2) reduce the rate of interest and commitment fees applicable thereunder and (3) make certain other changes to the terms and conditions of the prior credit facilities.
•In June 2023, CQP issued $1.4 billion aggregate principal amount of 5.95% Senior Notes due 2033 (the “2033 CQP Senior Notes”). Using contributed proceeds from the 2033 CQP Senior Notes together with cash on hand, SPL redeemed $1.4 billion of its 5.75% Senior Secured Notes due 2024 (the “2024 SPL Senior Notes”) in July 2023.
•In January 2023, we achieved our second issuer investment grade credit rating from Fitch Ratings of BBB- with a stable outlook. In February 2023, S&P Global Ratings upgraded its issuer credit rating of SPL from BBB to BBB+
with a stable outlook.
•During the three and six months ended June 30, 2023, we accomplished the following pursuant to our capital allocation priorities:
◦We prepaid $201 million and $1.1 billion, respectively,of consolidated long-term indebtedness pursuant to our capital allocation plan, inclusive of $201 million and $600 million, respectively, of debt repurchases in the open market.
◦We repurchased approximately 2.3 million shares and 5.4 million shares, respectively, of our common stock as part of our share repurchase program for $337 million and $788 million, respectively.
◦We paid dividends of $0.395 and $0.790 per share of common stock during the three and six months ended June 30, 2023, respectively.
◦We continued to invest in accretive organic growth, including the Corpus Christi Stage 3 Project, as further described under Investing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources.
Results
of Operations
Consolidated results of operations
Three
Months Ended June 30,
Six Months Ended June 30,
(in millions, except per share data)
2023
2022
Variance
2023
2022
Variance
Revenues
LNG
revenues
$
3,919
$
7,873
$
(3,954)
$
11,010
$
15,213
$
(4,203)
Regasification revenues
33
68
(35)
67
136
(69)
Other
revenues
150
66
84
335
142
193
Total
revenues
4,102
8,007
(3,905)
11,412
15,491
(4,079)
Operating
costs and expenses (recoveries)
Cost (recovery) of sales (excluding items shown separately below)
912
5,752
(4,840)
(627)
13,088
(13,715)
Operating
and maintenance expense
487
419
68
931
808
123
Selling, general and administrative expense
87
77
10
194
173
21
Depreciation
and amortization expense
297
276
21
594
547
47
Other
11
6
5
21
11
10
Total
operating costs and expenses
1,794
6,530
(4,736)
1,113
14,627
(13,514)
Income
from operations
2,308
1,477
831
10,299
864
9,435
Other
income (expense)
Interest expense, net of capitalized interest
(291)
(357)
66
(588)
(706)
118
Gain
(loss) on modification or extinguishment of debt
(2)
(28)
26
18
(46)
64
Interest rate derivative gain (loss), net
—
(1)
1
—
2
(2)
Interest
income
55
7
48
89
8
81
Other income (expense), net
—
(4)
4
3
—
3
Total
other expense
(238)
(383)
145
(478)
(742)
264
Income
before income taxes and non-controlling interest
2,070
1,094
976
9,821
122
9,699
Less: income tax provision (benefit)
363
181
182
1,679
(10)
1,689
Net
income
1,707
913
794
8,142
132
8,010
Less: net income attributable to non-controlling interest
338
172
166
1,339
256
1,083
Net
income (loss) attributable to common stockholders
$
1,369
$
741
$
628
$
6,803
$
(124)
$
6,927
Net
income (loss) per share attributable to common stockholders—basic
$
5.65
$
2.92
$
2.73
$
27.99
$
(0.49)
$
28.48
Net income
(loss) per share attributable to common stockholders—diluted
LNG
from the Liquefaction Projects sold under third party long-term agreements (1)
$
2,752
$
5,430
$
(2,678)
$
6,492
$
9,568
$
(3,076)
LNG
from the Liquefaction Projects sold by our integrated marketing function under short-term agreements
1,037
2,171
(1,134)
4,281
5,269
(988)
LNG procured from third parties
132
135
(3)
132
393
(261)
Net
derivative gains (losses)
(53)
85
(138)
1
(139)
140
Other revenues
51
52
(1)
104
122
(18)
Total
LNG revenues
$
3,919
$
7,873
$
(3,954)
$
11,010
$
15,213
$
(4,203)
Volumes
delivered as LNG revenues (in TBtu):
LNG from the Liquefaction Projects sold under third party long-term agreements (1)
495
487
8
1,006
957
49
LNG
from the Liquefaction Projects sold by our integrated marketing function under short-term agreements
52
83
(31)
160
194
(34)
LNG procured from third parties
14
4
10
14
15
(1)
Total
volumes delivered as LNG revenues
561
574
(13)
1,180
1,166
14
(1)Long-term
agreements include agreements with an initial tenure of 12 months or more.
Net income (loss) attributable to common stockholders
The favorable variances of $628 million and $6.9 billion for the three and six months ended June 30, 2023, respectively, as compared to the same periods of 2022, were primarily attributable to:
•favorable variances of $1.7 billion and $9.9 billion (before tax and the impact of non-controlling interest) between the three and six months ended June 30, 2023, respectively, as compared to the same periods of 2022, from changes in fair value and settlement of derivatives between the periods, to gains of $770 million and $5.4 billion in the three and six
months ended June 30, 2023, respectively, from losses of $937 million and $4.5 billion in the three and six months ended June 30, 2022, respectively, primarily related to non-cash favorable changes in fair value of our IPM agreements where we procure natural gas at a price indexed to international gas prices as a result of continued moderation of international gas price volatility and declines in international forward commodity curves.
The favorable variances were offset by:
•unfavorable variances of $182 million and $1.7 billion in income tax provision (benefit) between the three and six months ended June 30, 2023, respectively, as compared to the same periods of 2022;
•increases
in net income attributable to non-controlling interest of $166 million and $1.1 billion between the three and six months ended June 30, 2023, respectively, as compared to the same periods of 2022; and
•decreased LNG revenues, net of cost (recovery) of sales and excluding the effect of derivatives (as further described above), of $820 million and $428 million between the three and six months ended June 30, 2023, respectively, as compared to the same periods of 2022, the majority of which was attributable to
lower margins on LNG delivered.
The following is an additional discussion of the significant drivers of the variance in net income (loss) attributable to common stockholdersby line item:
Revenues
The decreases of $3.9 billion and $4.1 billion between the three and six months ended June 30, 2023, respectively, as compared to the same periods of 2022, were primarily attributable to:
•decreased Henry Hub pricing, which contributed $2.8 billion and $3.6 billion decreases between the three and six months ended June 30, 2023, respectively, as compared
to the same periods of 2022, for which the majority of our long-term contracts are indexed; and
•decreases of $1.1 billion and $1.2 billion between the three and six months ended June 30, 2023, respectively, as compared to the same periods of 2022, in revenues generated by our marketing function due to a reduction of volumes sold under short-term agreements and declining international prices.
Operating costs and expenses (recoveries)
The $4.7 billion and $13.5 billion favorable variances between the three and six months ended June 30, 2023, respectively, as compared
to the same periods of 2022, were primarily attributable to:
•$1.8 billion and $9.8 billion favorable variances between the three and six months ended June 30, 2023, respectively, as compared to the same periods of 2022, from changes in fair value and settlements of derivatives included in cost of sales, from $1.0 billion and $4.4 billion of losses in the three and six months ended June 30, 2022, respectively, to $822 million and $5.4 billion of gains in the three and six months ended June 30, 2023, respectively, primarily related to non-cash favorable changes in fair value of our IPM agreements as described above under the caption Net income (loss) attributable to common stockholders; and
•$3.0 billion
and $3.9 billion decreases between the three and six months ended June 30, 2023, respectively, as compared to the same periods of 2022, in cost of sales excluding the effect of derivative changes described above, primarily as a result of $3.0 billion and $4.0 billion, respectively, in decreased cost of natural gas feedstock largely due to lower U.S. natural gas prices.
The favorable variances were partially offset by increases in operating and maintenance expense of $68 million and $123 million for the three and six months ended June 30, 2023, respectively, as compared to the same periods of 2022. For the three months ended June 30, 2023, increases in operating and maintenance expense were primarily due to the completion of planned large-scale maintenance
activities on two trains at the SPL Project during June 2023. Further contributing to the increase in operating and maintenance expense during the six months ended June 30, 2023 was other third party service and maintenance contract costs and natural gas transportation and storage capacity demand charges.
Other income (expense)
The $145 million and $264 million favorable variances between the three and six months ended June 30, 2023, respectively, as compared to the same periods of 2022, were primarily attributable to:
•$66 million and $118 million
decreases in interest expense, net of capitalized interest between the three and six months ended June 30, 2023, respectively, as compared to the same periods of 2022, as a result of lower debt balances due to repayment of debt in accordance with our capital allocation plan and lower interest costs due to refinancing higher cost debt;
•$48 million and $81 million increases in interest income between the three and six months ended June 30, 2023, respectively, as compared to the same periods of 2022 attributable to higher interest income earned on cash and cash equivalents from higher interest rates in 2023; and
•$26 million and $64 million favorable variances in gain (loss) on modification or extinguishment of debt between the three and
six months ended June 30, 2023, respectively, as compared to the same periods of 2022, primarily due to
higher losses recognized from the amendment and restatement of CCH’s term loan facility agreement (the “CCH Credit Facility”) and CCH’s working capital facility agreement (the “CCH Working Capital Facility”) during the second quarter of 2022 and the redemption of our 4.25% Convertible Senior Notes due in 2045 (the “2045 Cheniere Convertible Senior Notes”) during the first quarter of 2022, as compared to a minimal loss recognized in the second quarter of
2023. Further contributing to the favorable variance during the six months ended June 30, 2023 was a reduction in premiums paid for the early redemption or repayment of debt principal, as further detailed under Financing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources.
Income tax provision (benefit)
The $182 million and $1.7 billion unfavorable variances between the three and six months ended June 30, 2023, respectively, as compared to the same periods of 2022, were primarily attributable
to an increase in pre-tax income.
Our effective tax rate was 17.5% and 17.1% for the three and six months ended June 30, 2023, respectively, as compared to 16.5% and(8.2)% for the three and six months ended June 30, 2022, respectively. Our effective tax rate was less than the statutory tax rate of 21% primarily due to CQP income that is not taxable to us. The effective tax rate for the six months ended June 30, 2022 was also impacted by discrete tax benefits primarily related to stock-based compensation awards.
Net income attributable to non-controlling interest
The
$166 million and $1.1 billion increase between the three and six months ended June 30, 2023, respectively, as compared to the same periods of 2022, was primarily attributable to $280 million and $2.1 billion increase in CQP’s consolidated net income between the three and six months ended June 30, 2023, respectively, as compared to the same periods of 2022.
Significant factors affecting our results of operations
Below are significant factors that affect our results of operations.
Gains and losses on derivative instruments
Derivative instruments,
which in addition to managing exposure to commodity-related marketing and price risks are utilized to manage exposure to changing interest rates and foreign exchange volatility, are reported at fair value on our Consolidated Financial Statements. For commodity derivative instruments related to our IPM agreements, 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 that may be outside of our control, notwithstanding the operational intent to mitigate risk exposure over time.
Commissioning cargoes
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 $204 million corresponding to 15 TBtu attributable to the sale of commissioning cargoes from Train 6 of the SPL Project. We did not have
any commissioning cargoes during the three months ended June 30, 2022 or the three and six months ended June 30, 2023.
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 cash and cash equivalents, restricted cash and cash equivalents and available commitments under our credit facilities. Additionally, we expect to meet our long term cash requirements by using operating cash flows and other future potential sources of liquidity, which may include debt and equity offerings by us or our subsidiaries. The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.
Restricted cash and cash equivalents designated for the following purposes:
SPL Project
241
CCL
Project
152
Cash held by our subsidiaries that is restricted to Cheniere
247
Total restricted cash and cash equivalents
640
Available commitments under our credit facilities (2):
SPL
Revolving Credit Facility
671
CQP Revolving Credit Facility
1,000
CCH Credit Facility
3,260
CCH Working Capital Facility
1,345
Cheniere’s
revolving credit agreement (the “Cheniere Revolving Credit Facility”)
1,250
Total available commitments under our credit facilities
7,526
Total available liquidity
$
12,695
(1)Amounts
presented include balances held by our consolidated variable interest entity, CQP, as discussed in Note 7—Non-controlling Interest and Variable Interest Entity of our Notes to Consolidated Financial Statements. As of June 30, 2023, assets of CQP, which are included in our Consolidated Balance Sheets, included $1.8 billion of cash and cash equivalents, of which $1.4 billion was used to partially redeem the 2024 SPL Senior Notes in July 2023.
(2)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of June 30, 2023. See Note
9—Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities and other debt instruments.
Our liquidity position subsequent to June 30, 2023 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. For further discussion of our future sources and uses of liquidity, see the liquidity and capital resources disclosures in our annual report on Form 10-K for the fiscal year ended December 31, 2022.
Although our sources and uses of cash are presented
below from a consolidated standpoint, SPL, CQP, CCH and Cheniere operate with independent capital structures. Certain restrictions under debt and equity instruments executed by our subsidiaries limit each entity’s ability to distribute cash, including the following:
•SPL and CCH are required to deposit all cash received into restricted cash and cash equivalents accounts under certain of their debt agreements. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Projects and other restricted payments. In addition, SPL and CCH’s operating expenses are managed by our subsidiaries under affiliate agreements, which may require SPL and CCH to advance cash to the respective
affiliates, however the cash remains restricted to Cheniere for operation and construction of the Liquefaction Projects;
•CQP is required under its partnership agreement to distribute to unitholders all available cash on hand at the end of a quarter less the amount of any reserves established by its general partner. Beginning with the distribution paid in the second quarter of 2022, quarterly distributions by CQP are comprised of a base amount plus a variable amount equal to the remaining available cash per unit, which takes into consideration, among other things, amounts reserved for annual debt repayment
and capital allocation goals, anticipated capital expenditures to be funded with cash, and cash reserves to provide for the proper conduct of CQP’s business;
•Our 48.6% limited partner interest, 100% general partner interest and incentive distribution rights in CQP limit our right to receive cash held by CQP to the amounts specified by the provisions of CQP’s partnership agreement; and
•SPL and CCH are restricted by affirmative and negative covenants included in certain of their debt agreements in their ability to make certain payments, including distributions, unless specific requirements are satisfied.
Despite the restrictions noted above, we believe that sufficient flexibility exists within the Cheniere complex to enable each independent capital
structure to meet its currently anticipated cash requirements. The sources of liquidity at SPL, CQP and CCH primarily fund the cash requirements of the respective entity, and any remaining liquidity not subject to restriction, as supplemented by liquidity provided by Cheniere Marketing, is available to enable Cheniere to meet its cash requirements.
Corpus Christi Stage 3 Project
The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as of June 30, 2023:
Overall
project completion percentage
38.1%
Completion percentage of:
Engineering
63.5%
Procurement
56.3%
Subcontract work
47.1%
Construction
4.9%
Date
of expected substantial completion
2H 2025 - 1H 2027
Sources and Uses of Cash
The following table summarizes the sources and uses of our cash, cash equivalents and 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.
Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents
3
—
Net
increase in cash, cash equivalents and restricted cash and cash equivalents
$
2,682
$
1,149
Operating Cash Flows
Our operating cash net inflows
during the six months ended June 30, 2023 and 2022 were $5.0 billion and $5.2 billion, respectively. The $172 million decrease between the periods was primarily related to timing of cash receipts and payments and lower cash receipts from the sale of LNG cargoes which was partially offset by lower cash outflows for natural gas feedstock, mostly due to lower U.S. natural gas prices.
We are not subject to the 15% corporate alternative minimum tax (“CAMT”) in 2023 based on enacted law and regulatory guidance; however, our CAMT status for 2023 could change in the future, depending on new regulations or regulatory guidance issued by the U.S. Department of the Treasury. The CAMT may cause volatility in our cash tax payment
obligations, particularly in periods of significant commodity, currency or financial market variability resulting from potential changes in the fair value of our derivative instruments.
Investing Cash Flows
Our investing cash net outflows in both years primarily were for the construction costs for the Liquefaction Projects. The $35 million increase in 2023 compared to 2022 was primarily due to spend during the six months ended June 30, 2023 related to increased construction work performed by Bechtel for the Corpus Christi Stage 3 Project following our issuance of full notice to proceed to Bechtel in June 2022, partially offset by a decrease in spend due to the completion
of Train 6 of the SPL Project in February 2022. We expect our capital expenditures to increase in future periods as construction work progresses on the Corpus Christi Stage 3 Project.
Financing Cash Flows
The following table summarizes our financing activities (in millions):
During the six months ended June 30, 2023, CQP issued an aggregate principal amount of $1.4 billion of 2033 CQP Senior
Notes. During the six months ended June 30, 2022, we had total borrowings of $575 million on the Cheniere Revolving Credit Facility and $440 million on the CCH Credit Facility. The proceeds from the borrowings during the six months ended June 30, 2022, together with cash on hand, were used to redeem or repurchase $2.7 billion of outstanding indebtedness, entirely associated with redemptions of our outstanding notes or repayment of amounts outstanding under our credit facilities.
Total
redemptions, repayments and repurchases of debt
$
(1,098)
$
(2,715)
Non-Controlling Interest Distributions
We
own a 48.6% limited partner interest in CQP with the remaining non-controlling limited partner interest held by Blackstone Inc., Brookfield Asset Management Inc. and the public. CQP paid distributions of $513 million and $427 million during the six months ended June 30, 2023 and 2022, respectively, to non-controlling interests.
Repurchase of Common Stock
During the six months ended June 30, 2023 and 2022, we paid $774 million and $565 million to repurchase 5.4 million and 4.4 million shares of our common stock, respectively, as part of our share repurchase program. As of June 30, 2023, we had
approximately $2.8 billion remaining under our share repurchase program.
Cash Dividends to Stockholders
During the six months ended June 30, 2023, we paid aggregate dividends of $0.790 per share of common stock, for a total of $195 million paid to common stockholders. We paid aggregate dividends of $0.66 per share of common stock, for a total of $170 million during the six months ended June 30, 2022.
On July 28, 2023, we declared a quarterly dividend of $0.395 per share of common stock that is payable on August 16, 2023
to stockholders of record as of the close of business on August 9, 2023.
Summary of Critical Accounting Estimates
The preparation of Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated 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, 2022.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Marketing and Trading Commodity Price Risk
We have commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the SPL Project and the CCL Project, and associated economic hedges (collectively, “Liquefaction Supply Derivatives”). We have also entered into physical and financial derivatives to hedge the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (collectively, “LNG Trading Derivatives”). In order to test the sensitivity of the fair value
of the Liquefaction Supply Derivatives and the LNG Trading Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location and a 10% change in the commodity price for LNG, respectively, as follows (in millions):
See Note 6—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our commodity derivative instruments.
Foreign Currency Exchange Risk
We
have entered into foreign currency exchange (“FX”) contracts to hedge exposure to currency risk associated with operations in countries outside of the United States (“FX Derivatives”). In order to test the sensitivity of the fair value of the FX Derivatives to changes in FX rates, management modeled a 10% change in FX rate between the U.S. dollar and the applicable foreign currencies as follows (in millions):
See Note
6—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our foreign currency derivative instruments.
ITEM 4. CONTROLS AND PROCEDURES
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.
ITEM 2. UNREGISTERED
SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Purchase of Equity Securities by the Issuer and Affiliated Purchasers
The following table summarizes stock repurchases for the three months ended June 30, 2023:
Period
Total
Number of Shares Purchased (1)
Average Price Paid Per Share (2)
Total Number of Shares Purchased as a Part of Publicly Announced Plans
Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans
April 1 - 30, 2023
298,351
$151.52
298,165
$3,129,549,054
May 1
- 31, 2023
1,081,091
$144.47
1,081,091
$2,973,366,327
June 1 - 30, 2023
922,564
$147.42
922,564
$2,837,366,110
Total
2,302,006
2,301,820
(1)Includes
issued shares surrendered to us by participants in our share-based compensation plans for payment of applicable tax withholdings on the vesting of share-based compensation awards. Associated shares surrendered by participants are repurchased pursuant to terms of the plan and award agreements and not as part of the publicly announced share repurchase plan.
(2)The price paid per share was based on the average trading price of our common stock on the dates on which we repurchased the shares.
ITEM 5. OTHER INFORMATION
Rule 10b5-1 under the Exchange Act provides an affirmative defense that enables prearranged transactions
in securities in a manner that avoids concerns about initiating transactions at a future date while possibly in possession of material nonpublic information. Our Insider Trading Policy permits our directors and executive officers to enter into trading plans designed to comply with Rule 10b5-1. During the three-month period ending June 30, 2023, iiiinone///
of our executive officers or directors adopted or terminated a Rule 10b5-1 trading plan or adopted or terminated a non-Rule 10b5-1 trading arrangement (as defined in Item 408(c) of Regulation S-K).
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.