CALIFORNIA RESOURCES CORPORATION We are an independent oil and natural gas exploration and production company operating properties exclusively withinCalifornia . We are incorporated inDelaware and became a publicly traded company onDecember 1, 2014 . Except when the context otherwise requires or where otherwise indicated, all references to ''CRC,'' the ''Company,'' ''we,'' ''us'' and ''our'' refer toCalifornia Resources Corporation and its subsidiaries. The following discussion should be read in conjunction with the other sections of this 2019 10-K, including Part I, Item 1A - Risk Factors and Part II, Item 8 - Financial Statements and Supplementary Data.
Basis of Presentation and Certain Factors Affecting Comparability
All financial information presented consists of our consolidated results of operations, financial position and cash flows unless otherwise indicated. The assets and liabilities in the consolidated financial statements are presented on a historical cost basis. We have eliminated all significant intercompany transactions and accounts. We account for our share of oil and natural gas production activities, in which we have a direct working interest, by reporting our proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on our balance sheets and statements of operations and cash flows. Production and Prices The following table sets forth our average net production volumes of oil, NGLs and natural gas per day for the years endedDecember 31, 2019 , 2018 and 2017: 2019 2018 2017 Net(a) Net(a) Net(a) Oil (MBbl/d) San Joaquin Basin 52 53 52 Los Angeles Basin 24 25 27 Ventura Basin 4 4 4 Total 80 82 83 NGLs (MBbl/d) San Joaquin Basin 15 15 15 Ventura Basin - 1 1 Total 15 16 16 Natural gas (MMcf/d) San Joaquin Basin 162 165 140 Los Angeles Basin 2 1 1 Ventura Basin 5 7 8 Sacramento Basin 28 29 33 Total 197 202 182
Total Production (MBoe/d)(a)(b) 128 132 129
Note: MBbl/d refers to thousands of barrels per day; MMcf/d refers to millions of
cubic feet per day; MBoe/d refers to thousands of barrels of oil equivalent
per day.
(a) Our acquisition of the remaining working interest in the
added approximately 10 MBoe/d and 8 MBoe/d in 2019 and 2018, respectively.
Our divestiture of a 50% working interest in certain zones within our Lost
Hills field resulted in a decrease of approximately 2 MBoe/d beginning in
2019. PSC-type contracts had no impact on our oil production in 2019
compared to 2018. Our PSC-type contracts negatively impacted our oil
production in 2018 by over 1 MBoe/d compared to 2017.
(b) Natural gas volumes have been converted to Boe based on the equivalence of
energy content of six thousand cubic feet of natural gas to one barrel of
oil. Barrels of oil equivalence does not necessarily result in price
equivalence.
47
-------------------------------------------------------------------------------- Our operating results and those of the oil and natural gas industry as a whole are heavily influenced by commodity prices. Oil and natural gas prices and differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it impossible to predict realized prices reliably. The following table sets forth average benchmark prices, average realized prices and price realizations as a percentage of average benchmark prices for our products for the years endedDecember 31, 2019 , 2018 and 2017: 2019 2018 2017 Price Realization Price Realization Price Realization
Oil ($ per Bbl) Brent$ 64.18 $ 71.53 $ 54.82 Realized price without hedge$ 64.83 101%$ 70.11 98%$ 51.47 94% Settled hedges 3.82 (7.51 ) (0.23 ) Realized price with hedge$ 68.65 107%$ 62.60 88%$ 51.24 93% WTI$ 57.03 $ 64.77 $ 50.95 Realized price without hedge$ 64.83 114%$ 70.11 108%$ 51.47 101% Realized price with hedge$ 68.65 120%$ 62.60 97%$ 51.24 101% NGLs ($ per Bbl) Realized price(a)$ 31.71 49%$ 43.67 61%$ 35.76 65% Realized price(b)$ 31.71 56%$ 43.67 67%$ 35.76 70% Natural gas NYMEX ($/MMBTU)$ 2.67 $ 2.97 $ 3.09 Realized price without hedge ($/Mcf)$ 2.87 107%$ 3.00 101%$ 2.67 86% Settled hedges (0.01 ) (0.02 ) - Realized price with hedge ($/Mcf)$ 2.86 107%$ 2.98 100%$ 2.67 86%
Note: We adopted a new revenue recognition standard on
required certain sales-related costs to be reported as expense as opposed
to being netted against revenue. The adoption of this standard did not
affect net income. Results for reporting periods beginning January 1, 2018 are presented under the new accounting standard while prior periods are not
adjusted and continue to be reported under accounting standards in effect
for the applicable period.
(a) Realization is calculated as a percentage of Brent. (b) Realization is calculated as a percentage of WTI.
Joint Ventures
We have entered into a number of joint ventures that allow us to use outside sources of capital to accelerate the development of our assets while providing us with operational and financial flexibility as well as near-term production benefits.Development Joint Ventures Alpine JV InJuly 2019 , we entered into a development joint venture withAlpine Energy Capital, LLC (Alpine) to develop portions of ourElk Hills field (Alpine JV). Alpine is a joint venture between subsidiaries of Colony Capital, Inc. (Colony) andEquity Group Investments . Alpine committed to invest$320 million , which may be increased to a total investment of$500 million , subject to the mutual agreement of the parties. The initial commitment is expected to be invested over a period of up to three years in accordance with a 275-well development plan. Alpine will fund 100% of the drilling and completion costs of these wells, in which they will earn a 90% working interest. If Alpine receives an agreed upon return, our working interest in those wells will increase from 10% to 82.5%. Our consolidated financial statements reflect only our working interest share in the productive wells. 48
-------------------------------------------------------------------------------- In connection with the Alpine JV, Colony received a warrant to purchase up to 1.25 million shares of our common stock at an exercise price of$40 per share. Colony will be entitled to exercise the warrant in tranches as funding milestones are achieved. The value of each tranche is recognized in our consolidated balance sheets when a funding milestone begins. Each tranche has a five-year term commencing on the date on which such tranche becomes exercisable. As ofDecember 31, 2019 , 200,000 shares of our common stock were exercisable under this warrant. Colony may elect, in its sole discretion, to pay cash or to exercise the warrant on a cashless basis, pursuant to which Colony will not be required to pay cash for shares of our common stock upon exercise of the warrant but will instead receive fewer shares.
Royale JV
InOctober 2018 , we entered into a three-year development joint venture for a 20-well program with Royale Energy, Inc. (Royale) where Royale committed approximately$23 million , of which$8 million has been funded to date. We committed to investing approximately$13 million , of which$4 million has been funded to date. Our consolidated results reflect only our 40% working interest share of production from these wells.
MIRA JV
InApril 2017 , we entered into a development joint venture with Macquarie Infrastructure andReal Assets Inc. (MIRA) to develop certain of our oil and natural gas properties in exchange for a 90% working interest in the related properties (MIRA JV). MIRA funded 100% of the drilling and completion costs of agreed-upon wells in the drilling program. Our 10% working interest increases to 75% if MIRA receives cash distributions equal to a predetermined threshold return. Of the initial$140 million agreed-upon capital commitment,$138 million was funded throughDecember 31, 2019 . Our consolidated results reflect only our working interest share in the productive wells.
BSP JV
InFebruary 2017 , we entered into a development joint venture withBenefit Street Partners (BSP) where BSP cumulatively contributed$200 million over a period of approximately two years in exchange for preferred interests in the BSP JV (BSP JV). BSP is entitled to preferential distributions and, if BSP receives cash distributions equal to a predetermined threshold, the preferred interest is automatically redeemed in full with no additional payment. The funds contributed by BSP were used to develop certain of our oil and natural gas properties. The BSP JV holds net profits interests (NPI) in existing and future cash flow from certain of our properties and the proceeds from the NPI are used by the BSP JV to (1) pay quarterly minimum distributions to BSP, (2) make additional distributions to BSP until the predetermined threshold is achieved, and (3) pay for development costs within the project area, upon mutual agreement between members. Our consolidated results reflect the full operations of the BSP JV, with BSP's share of net income reported in net income attributable to noncontrolling interests on our consolidated statements of operations.
The following table summarizes the cumulative investment through
Cumulative Investment through
December 31, 2019
(in millions)
Alpine $ 134
Royale 8
MIRA 138
BSP 200
Total Capital $ 480
49
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Midstream JV Ares JV InFebruary 2018 , we entered into a midstream joint venture withECR Corporate Holdings L.P. (ECR), a portfolio company ofAres Management L.P. (Ares). This joint venture (Ares JV) holds theElk Hills power plant (a 550-megawatt natural gas fired power plant) and a 200 MMcf/d cryogenic gas processing plant. We hold 50% of the Class A common interest and 95.25% of the Class C common interest in the Ares JV. ECR holds 50% of the Class A common interest, 100% of the Class B preferred interest and 4.75% of the Class C common interest. We received$750 million in proceeds upon entering into the Ares JV, before$3 million of transaction costs. The Class A common and Class B preferred interests held by ECR are reported as redeemable noncontrolling interests in mezzanine equity due to an embedded optional redemption feature. The Class C common interest held by ECR is reported in equity on our consolidated balance sheets. The Ares JV is required to make monthly distributions to the Class B holder. The Class B preferred interest has a deferred payment feature whereby a portion of the monthly distributions may be deferred for the first three years to the fourth and fifth year. The deferred amounts accrue an additional return. Distributions to the Class B preferred interest holders are reported as a reduction to mezzanine equity on our consolidated balance sheets. Monthly, the Ares JV is required to distribute its excess cash flow over its working capital requirements to the Class C common interests on a pro-rata basis. We can cause the Ares JV to redeem ECR's Class A and Class B interests, in whole, but not in part, at any time by paying$750 million for the Class B interest and$60 million for the Class A interest, plus any previously accrued but unpaid preferred distributions and a make-whole payment if the redemption happens prior to five years from inception. We have the option to extend the redemption period for up to an additional two and one-half years, in which case the interests can be redeemed for$750 million for the Class B interest and$80 million for the Class A interest, plus any previously accrued but unpaid preferred distributions and a make-whole payment if the redemption happens prior to seven and one-half years from inception. If we do not exercise a redemption at the end of the seven and one-half year period, ECR can either sell its Class A and Class B interests or cause the sale or lease of the Ares JV assets. Our consolidated statements of operations reflect the full operations of our Ares JV, with ECR's share of net income reported in net income attributable to noncontrolling interests. Additionally, in the first quarter of 2018, an Ares-led investor group purchased approximately 2.3 million shares of our common stock in a private placement for an aggregate purchase price of$50 million .
Exploration JVs
Since 2016, we have entered into multiple exploration joint ventures that have
allowed us to successfully explore multiple, diverse conventional exploration
prospects with industry-leading success with minimal internally funded capital.
In 2019, we drilled three exploration prospects with our partners under these
agreements.
We entered into additional exploration joint ventures in 2019 that generally
provided for our partners to invest in seismic and/or drilling activity across
our assets on a promoted basis.
50
--------------------------------------------------------------------------------Acquisitions and Divestitures
Acquisitions
InApril 2018 , we acquired fromChevron U.S.A., Inc. (Chevron ) its share of the remaining working, surface and mineral interests in the approximately 47,000-acreElk Hills unit (theElk Hills transaction) for approximately$518 million , including$7 million of liabilities assumed relating to asset retirement obligations. We accounted for theElk Hills transaction as a business combination and allocated$435 million to proved properties,$77 million to other property, plant and equipment and$6 million to materials and supplies. The consideration paid consisted of$460 million in cash and 2.85 million shares of CRC common stock issued at the close of the transaction (valued at$51 million ). As part of theElk Hills transaction,Chevron reduced its royalty interest in one of our oil and natural gas properties by half and extended the time frame to invest the remainder of our capital commitment on that property by two years, to the end of 2020. As ofDecember 31, 2019 , our remaining commitment was approximately$12 million . In addition, the parties mutually agreed to release each other from pending claims with respect to the formerElk Hills unit. InApril 2018 , we acquired an office building and land inBakersfield, California for$48 million . For the initial eight months in 2018, a former owner of the building occupied most of the space as a tenant, from which we generated approximately$4 million in rental income. InDecember 2018 , this tenant downsized the space they are leasing throughDecember 2022 , with a corresponding reduction in rent. The vacated space not used by us will be available to lease to other tenants to generate additional income. In addition, the unimproved land may be monetized in the future. Approximately$6 million of the purchase price was allocated to the in-place leases, which is included in other assets and is being amortized into other expenses, net.
Additionally, we had several other acquisitions totaling approximately
Divestitures
InMay 2019 , we sold 50% of our working interest and transferred operatorship in certain zones within ourLost Hills field, located in theSan Joaquin basin, for total consideration in excess of$200 million , consisting of approximately$168 million and a carried 200-well development program to be drilled through 2023 with an estimated value of$35 million (Lost Hills divestiture). We received cash proceeds of$164 million after transaction costs and purchase price adjustments, which were used to pay down our 2014 Revolving Credit Facility. In 2018, we divested non-core assets resulting in$18 million of proceeds and a$5 million gain. In 2017, we divested non-core assets resulting in$33 million of proceeds and a$21 million gain.
Seasonality
While certain aspects of our operations are affected by seasonal factors, such
as energy costs, overall, seasonality has not been a material driver of changes
in our earnings during the year.
51
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Income Taxes
All of our income is earned from domestic operations and is subject to tax in
the United States . We did not record a significant income tax provision
(benefit) in any of the years ended December 31, 2019 , 2018 and 2017.
Our effective tax rate differs from the amounts computed by applying the U.S.
federal statutory tax rate to pre-tax income (loss) as follows:
For the years ended
December 31,
2019 2018 2017
U.S. federal statutory tax rate 21 % 21 % (35 )%
State income taxes, net 7 6 (6 )
Exclusion of tax attributable to noncontrolling
interests, net (35 ) (5 ) -
Decrease in U.S. federal corporate tax rate - - 91
Tax credits, net (9 ) (6 ) (19 )
Nondeductible compensation, net 3 - -
Stock-based compensation, net - - 1
Change in valuation allowance, net 14 (17 ) (33 )
Other, net - 1 1
Effective tax rate 1 % - % - %
Our effective tax rate is primarily affected by state income taxes, income
included in our consolidated results which is taxed to noncontrolling interests
and the benefit of income tax credits. Our U.S. federal deferred tax assets and
liabilities were remeasured due to the reduction of the top corporate tax rate
from 35% to 21% under the Tax Cuts and Jobs Act (TCJA) enacted on December 22,
2017 . The TCJA also included significant changes to the deduction for executive
compensation by public corporations. Given our income tax position, any item
affecting our effective tax rate described above is generally offset by an equal
change in the valuation allowance.
Under the TCJA, for taxable years beginning in 2018, our deduction for business
interest is limited to 30% of our adjusted taxable income. For purposes of this
limitation, adjusted taxable income is computed without regard to net business
interest expense and, in the case of taxable years beginning before January 1,
2022 , any deduction allowable for depreciation, amortization or depletion.
Proposed Treasury Regulations issued in December 2018 provide that depreciation,
amortization or depletion expense that is capitalized to inventory is not
treated as depreciation, amortization or depletion for the purposes of computing
adjustable taxable income. It is reasonably possible that the composition of our
deferred tax assets, specifically the amount reported for net operating loss and
business interest expense carryforwards, could significantly change when the
Internal Revenue Service finalizes and issues regulations. Our carryforwards for
business interest expense do not expire.
Management assesses the available positive and negative evidence to estimate
whether sufficient future taxable income will be generated to permit use of
existing deferred tax assets. A significant piece of evidence evaluated is a
history of operating losses. Such evidence limits our ability to consider other
evidence such as projections for growth. As of December 31, 2019 , we concluded
that we could not realize, on a more-likely-than-not basis, any of our deferred
tax assets and there is not sufficient evidence to support the reversal of all
or any portion of this allowance. Given our recent and anticipated future
earnings trends, we do not believe any of the valuation allowance as of December
31, 2019 will be released within the next 12 months. Changes in assumptions or
changes in tax laws and regulations could materially affect the recognized
amounts of valuation allowance.
We paid approximately $1 million to California for alternative minimum taxes in
2019. We did not make any United States federal and state income tax payments in
2018 or 2017. We do not expect to make any significant income tax payments in
the foreseeable future, although this estimate could change.
For additional information on tax-related items, see information set forth in
Part II, Item 8 - Financial Statements and Supplementary Data, Note 10 Income
Taxes.
52
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Balance Sheet Analysis
Balance sheet components and changes in these components as of
2019 2018
(in millions)
Cash $ 17 $ 17
Trade receivables $ 277 $ 299
Inventories $ 67 $ 69
Other current assets, net $ 130 $ 255
Property, plant and equipment, net $ 6,352 $ 6,455
Other assets $ 115 $ 63
Current maturities of long-term debt $ 100 $ -
Accounts payable $ 296 $ 390
Accrued liabilities $ 313 $ 217
Long-term debt $ 4,877 $ 5,251
Deferred gain and issuance costs, net $ 146 $ 216
Other long-term liabilities $ 720 $ 575
Mezzanine equity $ 802 $ 756
Equity attributable to common stock $ (389 ) $ (361 ) Equity attributable to noncontrolling interests
Cash at
The decrease in trade receivables was largely driven by lower natural gas trading activity inDecember 2019 as compared withDecember 2018 , as well as a decline in production and natural gas and NGL realized prices in the fourth quarter of 2019 compared to the fourth quarter of 2018. These decreases were partially offset by higher realized oil prices inDecember 2019 compared toDecember 2018 .
The decrease in other current assets, net primarily reflected a decrease in the fair value of the current portion of our derivative assets, which primarily resulted from a lower percentage of our oil production hedged between comparative periods.
The decrease in property, plant and equipment, net primarily resulted from depreciation, depletion and amortization (DD&A) and theLost Hills divestiture, partially offset by capital investments and increases in our asset retirement obligations (ARO) resulting from idle well regulations enacted in the first quarter of 2019. The increase in other assets was primarily due to recording a long-term operating lease asset as a result of accounting rules adopted onJanuary 1, 2019 and prepaid power plant major maintenance, partially offset by a decrease in the fair value of long-term derivative assets.
Current maturities of long-term debt reflected
The decrease in accounts payable atDecember 31, 2019 compared toDecember 31, 2018 reflected the decrease in capital investments and gas-trading activities, which were lower in the fourth quarter of 2019 compared to the fourth quarter of 2018. The increase in accrued liabilities reflected the current portion of our operating lease liability resulting from the adoption of new lease accounting rules, the timing of payments due to our joint venture partners, severance costs related to ourOctober 2019 organizational restructure and increased obligation to purchase greenhouse gas allowances. 53 -------------------------------------------------------------------------------- Long-term debt decreased due to repurchases of our Second Lien Notes, reclassification of$100 million of our Senior Notes to current maturities of long-term debt, pay down of the 2014 Revolving Credit Facility from the proceeds of theLost Hills divestiture and positive cash flow.
The decrease in deferred gain and issuance costs, net was largely the result of repurchases of our Second Lien Notes and amortization.
Other long-term liabilities reflected the increase in ARO primarily due to idle well regulations enacted in the first quarter of 2019, long-term operating lease liabilities due to the adoption of new lease accounting rules and postretirement benefits primarily resulting from theOctober 2019 organizational restructure. The annual incremental cash expenditures for ARO resulting from the idle well regulations and postretirement benefits resulting from theOctober 2019 organizational restructure are not expected to be material in the foreseeable future.
Mezzanine equity reflected the carrying amount of the Class A common and Class B preferred interests held by ECR in our midstream JV.
Equity attributable to common stock decreased as a result of a decrease in net income between periods and an increase in the income allocated to ECR for a full 12 months in 2019 as compared to nine months in the prior year. Equity attributable to noncontrolling interests includes the Class C interest in the midstream joint venture held by ECR and BSP's preferred interest in the BSP JV. The decrease in 2019 primarily related to distributions to the noncontrolling interest holders.
Statement of Operations Analysis
Results of Oil and Natural Gas Operations
The following represents key operating data for our oil and natural gas
operations, excluding corporate items, on a per Boe basis for the years ended
2019 2018 2017
Production costs$ 19.16 $ 18.88 $ 18.64 Production costs, excluding effects of PSC-type contracts(a)$ 17.70 $ 17.47 $ 17.48 Field general and administrative expenses(b)$ 1.20 $ 1.01 $ 0.70 Field depreciation, depletion and amortization$ 9.40 $ 9.71 $ 10.85 Field taxes other than on income$ 2.59 $
2.42
(a) As described in Items 1 and 2 - Business and Properties - Operations -
Production, Price and Cost History, the reporting of our PSC-type contracts
creates a difference between reported production costs, which are for the
full field, and reported volumes, which are only our net share, inflating
the per barrel production costs. These amounts represent our production
costs after adjusting for this difference.
(b) Field general and administrative expenses increased in 2019 compared to
2018, primarily due to the
since certain costs are no longer recovered from our former working interest
partner. Our 2019 costs include 12 months without such cost recovery
compared to nine months without cost recovery in 2018.
Field general and administrative expenses also increased in 2018 compared to 2017 primarily due to theElk Hills transaction, with 2018 costs including nine months without cost recovery compared to 12 months of cost recovery in 2017. 54
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Consolidated Results of Operations
The following represents key operating data for consolidated operations for the
years ended
2019 2018 2017
(in millions)
Oil and natural gas sales(a) $ 2,270 $ 2,590 $ 1,936
Net derivative (loss) gain from commodity contracts (59 ) 1 (90 )
Other revenue(a) 423 473 160
Production costs (895 ) (912 ) (876 )
General and administrative expenses(b) (290 ) (299 ) (249 )
Depreciation, depletion and amortization (471 ) (502 ) (544 )
Taxes other than on income (157 ) (149 ) (136 )
Exploration expense (29 ) (34 ) (22 )
Other expenses, net(a) (363 ) (399 ) (106 )
Interest and debt expense, net (383 ) (379 ) (343 )
Net gain on early extinguishment of debt 126 57 4
Gain on asset divestitures - 5
21
Other non-operating expenses(b) (72 ) (23 ) (17 ) Income (loss) before income taxes 100 429 (262 ) Income tax provision (1 ) - - Net income (loss) 99 429 (262 ) Net income attributable to noncontrolling interests$ (127 ) $ (101 ) $ (4 ) Net (loss) income attributable to common stock$ (28 ) $ 328 $ (266 ) Adjusted net income (loss)(c)$ 70 $ 61 $ (187 ) Adjusted EBITDAX(c)$ 1,142 $ 1,117 $ 779 Effective tax rate 1 % - % - %
(a) We adopted the revenue recognition standard on
certain sales-related costs to be reported as expense as opposed to being
netted against revenue. The adoption of this standard did not affect net
income. Results for reporting periods beginning January 1, 2018 are
presented under the new accounting standard while prior periods are notadjusted and continue to be reported under accounting standards in effect
for the applicable period.
(b) New accounting rules related to the presentation of net periodic benefit
costs for pension and postretirement benefits in the Consolidated Statements
of Operations were adopted on
31, 2017, certain pension benefit costs of
from general and administrative expenses to other non-operating expenses to
conform with the new rules.
(c) Adjusted net income (loss) and Adjusted EBITDAX are non-GAAP measures. Seethe Non-GAAP Financial Measures section below for a reconciliations to their
nearest GAAP measures.
Year Ended
Oil and natural gas sales - Oil and natural gas sales, excluding the impact of settled hedges, decreased 12%, or$320 million , in 2019 compared to 2018, due to changes in realized prices and production as reflected in the following table: Oil NGLs Natural Gas Total (in millions)
Year ended
(9 ) (239 )
Changes in production (67 ) (10 ) (4 ) (81 )
Year ended
Note: See Production and Prices for average benchmark and realized prices, realizations and production.
The effect of settled hedges is not included in the table above. Proceeds from settled hedges were$111 million for the year endedDecember 31, 2019 compared to payments of$228 million in 2018, which had a positive impact of$339 million on our total revenue between years. Including the effect of settled hedges, our oil and natural gas sales increased by$19 million or 1% compared to the same period of 2018. 55
-------------------------------------------------------------------------------- Net derivative (loss) gain from commodity contracts - Net derivative loss from commodity contracts was$59 million for the year endedDecember 31, 2019 compared to a gain of$1 million in the same period of 2018, representing an overall change of$60 million as reflected in the following table. The non-cash changes in the fair value of our outstanding derivatives resulted from the positions held as well as the relationship between contract prices and the associated forward curves at the end of each year. Year endedDecember 31, 2019 2018 (in millions)
Non-cash derivative (loss) gain, excluding noncontrolling interest
(4 ) 5
Total non-cash changes (170 ) 229
Net proceeds (payments) on settled commodity derivatives 111 (228 )
Net derivative (loss) gain from commodity contracts $ (59 ) $ 1
Other revenue - Other revenue was $423 million for the year ended December 31,
2019 compared to $473 million in the same period of 2018, representing a
decrease of $50 million as reflected in the following table. This decrease was
largely the result of lower trading activity in 2019; however, the operating
margin before transportation charges in 2019 was $85 million compared to $80
million in 2018.
Year ended
December 31,
2019 2018
(in millions)
Trading $ 286 $ 330
Electricity sales 112 111
Other 25 32
Total other revenue $ 423 $ 473
Production costs - Production costs for the year ended December 31, 2019
decreased $17 million to $895 million , compared to $912 million for the same
period of 2018, resulting in a 2% decrease. The decrease primarily related to
cost savings resulting from our October 2019 organizational redesign and less
downhole maintenance activity in 2019 compared to the prior year.
General and administrative expenses - Our general and administrative expenses
decreased $9 million to $290 million for the year ended December 31, 2019
compared to the same period of 2018, predominantly due to cost savings
attributable to our October 2019 organizational redesign and lower cash-settled
stock-based compensation expense resulting from the approximately $8 decline in
our stock price at December 31, 2019 compared to December 31, 2018 . See the
Stock-Based Compensation section below.
Other expenses, net - Other expenses, net was $363 million for the year ended
December 31, 2019 compared to $399 million for the same period of 2018,
representing a decrease of $36 million as reflected in the following table. The
decrease was largely the result of lower trading activity, partially offset by
higher Elk Hills Power costs and transportation costs.
Year ended
December 31,
2019 2018
(in millions)
Trading purchases $ 201 $ 250
Elk Hills Power costs 68 61
Transportation costs 40 36
Other expenses 54 52
Total other expenses, net $ 363 $ 399
56
-------------------------------------------------------------------------------- Other non-operating expenses - Other non-operating expenses for the year endedDecember 31, 2019 increased$49 million to$72 million , compared to$23 million for the same period of 2018, resulting in an approximately 200% increase. This increase was primarily due to the implementation of fourth quarter 2019 operational efficiencies and an organizational redesign that reduced our workforce to approximately 1,250 employees, which is slightly more than half the employees we had at the time of our inception in 2014. We recorded a charge to other non-operating expenses of$41 million , consisting of$29 million in salary and severance expense and$12 million for other termination benefits. Net income attributable to noncontrolling interests - The increase in net income attributable to noncontrolling interests of$26 million reflected the additional net income (loss) allocated to ECR for the full year of 2019 compared to 2018 starting in April, partially offset by the change in the fair value of derivative instruments held by the BSP JV in 2019. Stock-Based Compensation Our consolidated results of operations for the years endedDecember 31, 2019 and 2018 include the effects of long-term stock-based compensation plans under which awards are granted annually to executives, non-executive employees and non-employee directors that are either settled with shares of our common stock or cash. Our equity-settled awards granted to executives include stock options, restricted stock units and performance stock units that either cliff vest at the end of a three-year period or vest ratably over a three-year period, some of which are partially settled in cash. Our equity-settled awards granted to non-employee directors are stock grants that vest immediately or restricted stock units that cliff vest after one year. Our cash-settled awards granted to non-executive employees vest ratably over a three-year period. Changes in our stock price introduce volatility in our results of operations because we pay cash-settled awards based on our stock price on the vesting date and accounting rules require that we adjust our obligation for unvested awards to the amount that would be paid using our stock price at the end of each reporting period. Cash-settled awards, including executive awards partially settled in cash, account for almost 70% of our total outstanding awards. Equity-settled awards are not similarly adjusted for changes in our stock price.
Our ending stock price for each of the quarters in 2019 and 2018 was as follows:
2019 2018
First quarter $ 25.71 $ 17.15
Second quarter $ 19.68 $ 45.44
Third quarter $ 10.20 $ 48.53
Fourth quarter $ 9.03 $ 17.04 Stock-based compensation is included in both G&A expenses and production costs as shown in the table below (in millions, except per Boe amounts):
2019 2018
G&A expenses
Cash-settled awards $ 14 $ 23
Equity-settled awards 11 13
Total stock-based compensation in G&A $ 25 $ 36
Total stock-based compensation in G&A per Boe$ 0.54 $ 0.75 Production costs Cash-settled awards$ 4 $ 6 Equity-settled awards 3 3
Total stock-based compensation in production costs
Total stock-based compensation in production costs per Boe
Total stock-based compensation$ 32 $
45
Total stock-based compensation per Boe$ 0.69 $ 0.94 57
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Year Ended
See Part II, Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations, Statement of Operations Analysis in our 2018 Form 10-K for our analysis of the changes in our consolidated statements of operations for the year endedDecember 31, 2018 compared toDecember 31, 2017 .
Non-GAAP Financial Measures
Adjusted net income (loss) - Our results of operations, which are presented in accordance withU.S. generally accepted accounting principles (GAAP), can include the effects of unusual, out-of-period and infrequent transactions and events affecting earnings that vary widely and unpredictably (in particular certain non-cash items such as derivative gains and losses) in nature, timing, amount and frequency. Therefore, management uses a measure called adjusted net income (loss) that excludes those items. This measure is not meant to disassociate these items from management's performance but rather is meant to provide useful information to investors interested in comparing our performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted net income (loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP. The following table presents a reconciliation of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of adjusted net income (loss) and presents the GAAP financial measure of net income (loss) attributable to common stock per diluted share and the non-GAAP financial measure of adjusted net income (loss) per diluted share: 2019 2018 2017 (in millions, except share data) Net income (loss)$ 99 $ 429 $ (262 ) Net income attributable to noncontrolling interests (127 ) (101 ) (4 ) Net (loss) income attributable to common stock (28 ) 328 (266 ) Unusual, infrequent and other items: Non-cash derivative loss (gain) from commodities, excluding noncontrolling interest 166 (224 ) 78 Non-cash derivative loss from interest-rate contracts 4 6 - Severance and termination benefits 47 4 5 Net gain on early extinguishment of debt (126 ) (57 ) (4 ) Gain on asset divestitures - (5 ) (21 ) Other, net 7 9 21 Total unusual, infrequent and other items 98 (267 ) 79 Adjusted net income (loss)$ 70 $
61
Net (loss) income attributable to common stock per diluted share
$ (0.57 ) $ 6.77 $ (6.26 ) Adjusted net income (loss) per diluted share$ 1.40 $
1.27
Adjusted EBITDAX - We define Adjusted EBITDAX as earnings before interest
expense; income taxes; depreciation, depletion and amortization; exploration
expense; other unusual, infrequent and out-of-period items; and other non-cash
items. We believe this measure provides useful information in assessing our
financial condition, results of operations and cash flows and is widely used by
the industry, the investment community and our lenders. Although this is a
non-GAAP measure, the amounts included in the calculation were computed in
accordance with GAAP. Certain items excluded from this non-GAAP measure are
significant components in understanding and assessing our financial performance,
such as our cost of capital and tax structure, as well as the historic cost of
depreciable and depletable assets. This measure should be read in conjunction
with the information contained in our financial statements prepared in
accordance with GAAP. A version of Adjusted EBITDAX is a material component of
certain of our financial covenants under our 2014 Revolving Credit Facility and
is provided in addition to, and not as an alternative for, income and liquidity
measures calculated in accordance with GAAP.
58
--------------------------------------------------------------------------------The following table presents a reconciliation of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of Adjusted EBITDAX:
2019 2018 2017
(in millions)
Net income (loss) $ 99 $ 429 $ (262 )
Interest and debt expense, net 383 379 343
Depreciation, depletion and amortization 471 502 544 Exploration expense
29 34 22
Unusual, infrequent and other items 98 (267 ) 79
Other non-cash items 62 40 53
Adjusted EBITDAX $ 1,142 $ 1,117 $ 779
The following table sets forth a reconciliation of the GAAP measure of net cash
provided by operating activities to the non-GAAP financial measure of Adjusted
EBITDAX:
2019 2018 2017
(in millions)
Net cash provided by operating activities $ 676 $ 461 $ 248
Cash interest 439 441 396
Exploration expenditures 18 17 20
Working capital changes 8 199 94
Other, net 1 (1 ) 21
Adjusted EBITDAX $ 1,142 $ 1,117 $ 779 Liquidity and Capital Resources
Cash Flow Analysis
2019 2018
(in millions)
Net cash provided by operating activities $ 676 $ 461
Net cash used in investing activities:
Capital investments $ (455 ) $ (690 )
Changes in capital investment accruals $ (85 ) $ 69
Acquisitions, divestitures and other $ 146 $ (535 )
Net cash (used) provided by financing activities:
Debt transactions $ (181 ) (Distributions) contributions with noncontrolling interest holders, net
$ (102 )
Issuance of common stock and other, net$ 1
Cash flows from operating activities - Our net cash provided by operating activities is sensitive to many variables, particularly changes in commodity prices. Commodity price movements may also lead to changes in other variables in our business, including adjustments to our capital program. Our operating cash flow increased 47%, or$215 million , to$676 million for the year endedDecember 31, 2019 from$461 million in the same period of 2018 primarily due to net proceeds on settled commodity derivatives of$111 million in 2019 compared to payments of$228 million in 2018, which was partially offset by a decrease in oil and gas revenue as a result of lower realized prices and production in 2019. Changes in operating assets and liabilities increased our operating cash flow in 2019 by$210 million compared to 2018, which was largely the result of purchasing more greenhouse gas allowances in 2018. The increase was also attributable to a decrease in purchased hedges and the timing of payments for capital investments. Cash flows from investing activities - Our net cash used in investing activities of$394 million for the year endedDecember 31, 2019 included$455 million of capital investments (excluding$85 million in negative capital-related accrual changes), of which$48 million was funded by BSP. These uses of cash were partially offset by$164 million in proceeds related to theLost Hills divestiture. 59 -------------------------------------------------------------------------------- Our net cash used in investing activities of$1,156 million for the year endedDecember 31, 2018 included$690 million of capital investments (excluding$69 million in positive capital-related accrual changes), of which$49 million was funded by BSP, and$547 million of acquisition costs primarily related to theElk Hills transaction and a building inBakersfield . These uses of cash were partially offset by$18 million in proceeds from the sale of non-core assets. The amounts in the table below reflect our capital investment, excluding changes in capital investment accruals, for the years endedDecember 31, 2019 and 2018: 2019 2018 (in millions) Oil and natural gas$ 379 $ 610 Exploration 9 21 Corporate and other 19 10 Total internally funded capital 407 641 BSP-funded capital 48 49 Total capital$ 455 $ 690 Cash flows from financing activities - Our net cash used in financing activities of$282 million for the year endedDecember 31, 2019 primarily resulted from$156 million of debt repurchases on our Second Lien Notes,$151 million of distributions to our noncontrolling interest holders and$23 million in net payments on our 2014 Revolving Credit Facility, partially offset by$49 million in net contributions from BSP.
For the year ended
Liquidity
Our primary sources of liquidity and capital resources are cash flows from operations and available borrowing capacity under our 2014 Revolving Credit Facility. We also rely on other sources such as joint ventures and non-core asset sales to supplement our capital program and fund other corporate purposes. Our working capital requirements are primarily driven by the level of activity in our business and debt service requirements. Our 2020 capital program will be dynamic and will be adjusted based on realized price trends during the year. As ofDecember 31, 2019 , we had available liquidity of$331 million , which consisted of$14 million in unrestricted cash and$317 million of available borrowing capacity under our 2014 Revolving Credit Facility (before a$150 million month-end minimum liquidity requirement). However, as ofDecember 31, 2019 , we had approximately$4.9 billion of debt outstanding, a substantial portion of which will mature in 2021. We have undertaken a variety of measures to reduce debt such as repurchasing outstanding notes and selling non-core assets. We have also increased our margins by reducing our workforce and consolidating our office space. OnFebruary 20, 2020 , we launched offers to exchange a significant portion of our Second Lien Notes and senior notes into (1) notes and equity interests issued by a non-consolidated entity that will hold a term royalty interest in ourElk Hills unit and/or (2) a new first-lien last-out Company term loan and warrants convertible into our common stock. If fully subscribed, the transaction would have the effect of reducing our net debt by almost$1 billion . The transaction is expected to close onMarch 20, 2020 . 60 -------------------------------------------------------------------------------- We are continuing to evaluate and consider a number of additional opportunities to delever, including liability management transactions, monetization of royalty and other property interests and other similar transactions. Such transactions, if any, will depend on prevailing market conditions, contractual restrictions and other factors. Our ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon oil and natural gas prices, the success of our development activities, our success with respect to our deleveraging efforts and our ability to refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by the results of our operations, economic and capital market conditions, oil and natural gas prices and other factors, many of which are beyond our control. See "We have significant indebtedness that could limit our financial and operating flexibility and make us more vulnerable in economic downturns," "Our lenders require us to comply with covenants that limit our borrowing capabilities and could restrict our ability to use or access capital" and "A significant portion of our long-term indebtedness will mature within two years and will likely need to be refinanced. There can be no assurances we will be able to refinance this indebtedness on acceptable terms or at all." in Part I, Item 1A - Risk Factors for additional information about our indebtedness and restrictions on our use of and access to capital.
We believe that our operating cash flows and availability under our 2014 Revolving Credit Facility will be sufficient to meet our obligations and working capital requirements for the next 12 months.
Debt
As of
Outstanding Interest
Principal Rate(a) Maturity Security
Credit Agreements (in millions)
LIBOR plus
3.25%-4.00% Shared
2014 Revolving Credit ABR plus First-Priority
Facility $ 518 2.25%-3.00% June 30, 2021 Lien
LIBOR plus
4.75% Shared
ABR plus December 31, First-Priority
2017 Credit Agreement 1,300 3.75% 2022(b) Lien
LIBOR plus
10.375%
ABR plus December 31, First-Priority
2016 Credit Agreement 1,000 9.375% 2021 Lien
Second Lien Notes
December 15, Second-Priority
Second Lien Notes 1,815 8% 2022(c) Lien
Senior Notes
5% Senior Notes due January 15,
2020 100 5% 2020 Unsecured
5½% Senior Notes due September 15,
2021 100 5.5% 2021 Unsecured
6% Senior Notes due November 15,
2024 144 6% 2024 Unsecured
Total $ 4,977
Less: Current
Maturities (100 )
Long-Term Debt 4,877
(a) London Interbank Offered Rates (LIBOR) will be phased out after 2021 and
replaced with the Secured Overnight Financing Rate within
for
discontinuation of LIBOR and have an alternate borrowing rate. We do not
expect the discontinuation of LIBOR to have a significant impact on our
carrying charges.
(b) The 2017 Credit Agreement is subject to a springing maturity of 91 days
prior to the maturity of our 2016 Credit Agreement if more than
in principal of the 2016 Credit Agreement is outstanding at that time.
(c) The Second Lien Notes require principal repayments of approximately
million in
2022 and
As ofDecember 31, 2019 , we had approximately$317 million of available borrowing capacity, subject to a$150 million month-end minimum liquidity requirement. Our 2014 Revolving Credit Facility also includes a sub-limit of$400 million for the issuance of letters of credit. As ofDecember 31, 2019 and 2018, we had letters of credit of approximately$165 million and$162 million , respectively. These letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters.
For additional information on long-term debt, see information set forth in Part II, Item 8 - Financial Statements and Supplementary Data, Note 6 Debt.
61
--------------------------------------------------------------------------------Derivatives
Commodity Contracts
Our strategy for protecting our cash flow, operating margin and capital program, while maintaining adequate liquidity, also includes our hedging program. We did not have any commodity derivatives designated as accounting hedges as of and during the year endedDecember 31, 2019 . We currently have the following Brent-based crude oil contracts, as ofFebruary 26, 2020 : Q1 Q2 Q3 Q4 2020 2020 2020 2020 Purchased Puts: Barrels per day 30,000 20,000 13,000 8,000
Weighted-average price per barrel
Sold Puts: Barrels per day 30,000 20,000 18,000 13,000
Weighted-average price per barrel
Swaps:
Barrels per day - 5,000 5,000 5,000
Weighted-average price per barrel $ -
Our counterparties have an option to increase volumes by up to 5,000 barrels per day for the second quarter of 2020 at a weighted-average Brent price of$70.05 . A counterparty has an option to increase volumes by up to 5,000 barrels per day for the second half of 2020 at a weighted-average Brent price of$65.00 . The BSP JV entered into crude oil derivatives for insignificant volumes through 2021 that are included in our consolidated results but not in the above table. The BSP JV also entered into natural gas swaps for insignificant volumes for periods throughMay 2021 . The hedges entered into by the BSP JV could affect the timing of the reversion of BSP's preferred interest.
Interest-Rate Contracts
InMay 2018 , we entered into derivative contracts that limit our interest rate exposure with respect to$1.3 billion of our variable-rate indebtedness. These interest rate contracts reset monthly and require the counterparties to pay any excess interest owed on such amount in the event the one-month LIBOR exceeds 2.75% for any monthly period prior toMay 4, 2021 .
Capital Program
We seek to create value by investing our operating cash flow back into our business. We respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings.
We focus our capital program on oil projects that provide high margins and low
decline rates. We believe investing in these projects will generate positive
cash flow allowing us to fund future capital programs and grow production over
the longer term. Our low decline rates compared to our industry peers together
with our high level of operational control give us the flexibility to adjust the
level of our capital investments as circumstances warrant.
We develop our capital program by prioritizing life-of-project returns to grow
our net asset value over the long term, while balancing the short- and long-term
growth potential of each of our assets. We use a Value Creation Index (VCI)
metric for project selection and capital allocation across our asset portfolio.
We calculate the VCI for each of our projects by dividing the net present value
of the project's expected pre-tax cash flow over its life by the net present
value of the investments, each using a 10% discount rate. Projects included in
our capital program are expected to meet a VCI of 1.3, meaning that 30% of
expected value is created above our cost of capital for every dollar invested
over the life of the project.
62
-------------------------------------------------------------------------------- Our technical teams are consistently working to enhance value by improving the economics of our inventory through detailed geologic studies as well as application of more effective and efficient drilling and completion techniques. As a result, we expect many projects that do not currently meet our VCI threshold today will do so by the time of development. We regularly monitor internal performance and external factors and adjust our capital investment program with the objective of creating the most value from our asset portfolio. Actions we have taken to streamline our business and reduce costs enable us to invest in our business to support production. In addition, we will continue to build our inventory of available projects, which we believe will position us to accelerate value by utilizing JV capital and take advantage of potential future commodity price increases. 2019 Capital Program
Sources of our 2019 capital program were as follows:
2019
(in millions)
Internally funded capital $ 407
BSP-funded capital 48
Capital investment included in our financial statements 455
MIRA-funded capital 23
Alpine-funded capital 134
Total capital investment $ 612
Our capital program targeted oil-weighted projects in the
Conventional Unconventional Total Capital
Primary Waterflood Steamflood Total Primary Other Investments
Basin: (in millions)
San Joaquin $ 32 $ 72 $ 40 $ 144 $ 162 $ - $ 306
Los Angeles - 93 - 93 - - 93
Ventura 10 4 - 14 - - 14
Sacramento 11 - - 11 - - 11
Exploration and
other - - - - - 31 31
Capital included
in our financial
statements 53 169 40 262 162 31 455
MIRA-funded
capital 23 - - 23 - - 23
Alpine-funded
capital 1 - 57 58 76 - 134
Total $ 77 $ 169 $ 97 $ 343 $ 238 $ 31 $ 612
The table below sets forth our capital investments by activity type for the year
ended
Drilling Workovers Facilities Exploration Other Total Capital
(in millions)
Internally funded $ 249 $ 53 $ 77 $ 9 $ 19 $ 407
BSP 45 - - 3 $ - $ 48
Capital
investments
included in our
financial
statements 294 53 77 12 $ 19 $ 455
MIRA-funded
capital 23 - - - $ - $ 23
Alpine-funded
capital 134 - - - $ - $ 134
Total $ 451 $ 53 $ 77 $ 12 $ 19 $ 612
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--------------------------------------------------------------------------------
2020 Capital Program
We entered 2020 with an internally funded capital program of$100 million to$300 million , which may be adjusted during the course of the year depending on commodity prices. Additionally, existing JV partners will increase our capital program by approximately$160 million to$200 million for a program total of$260 million to$500 million . We are currently operating seven drilling rigs funded by JV capital and one internally funded drilling rig. We are focusing our 2020 capital on short payout projects like capital workovers, especially in the first half of the year, as well as primary drilling of vertical and lateral wells and low-risk projects including waterflood and steamflood investments that maintain base production. Early in the year, our capital will be mostly focused on high-VCI short-payout workovers in addition to safety and maintenance-related projects. We may add more drilling projects as the year progresses depending on the overall commodity price environment. Our approach to our 2020 drilling and overall capital program is consistent with our stated strategy to remain financially disciplined and fund projects through either internally generated cash flow or JV capital. We will continue to deploy our partners' capital as part of our Alpine joint venture and opportunistically pursue additional strategic relationships. We will deploy capital to projects that help continue to stabilize our production, develop our long-term resources and return our production to a growth profile. Our current drilling inventory comprises a diversified portfolio of oil and natural gas locations that are economically viable in a variety of operating and commodity price conditions.
We will continue to focus our internally funded capital program on our core
areas:
We plan to invest approximately 40% of our internally funded 2020 capital program in capital workovers of existing well bores. Capital workovers inElk Hills and other fields are some of the highest VCI projects in our portfolio and generally include well deepenings, recompletions, changes in lift methods and other activities designed to add incremental productive intervals and reserves. We plan to invest approximately 35% of our capital on the development of conventional and unconventional projects. The depth of our conventional wells is expected to range from 2,000 to 12,000 feet. Our conventional program includes wells located primarily in theLos Angeles basin,Mount Poso and other appraisal long-term prospects primarily focused on waterflood and primary drilling. We also intend to drill unconventional wells mainly in the Buena Vista area. With continued focus on cost savings and efficiencies, many of our deep conventional and unconventional wells have become more competitive. Further, approximately 20% of our 2020 capital program is intended for facilities development for our newer projects, including pipeline and gathering line interconnections, gas compression and water management systems, and for mechanical integrity and health, safety and environmental projects. About 5% is intended to be used for exploration and other corporate uses. Efficiency gains in our capital costs have enabled us to maintain a robust capital program even in a low commodity price environment. We will continue to build our inventory of available projects, which will position us to accelerate value by utilizing third-party capital and take advantage of potential future commodity price increases. Off-Balance-Sheet Arrangements We have no off-balance-sheet arrangements other than the purchase obligations described in the Contractual Obligations section below. 64 -------------------------------------------------------------------------------- Contractual Obligations The table below summarizes and cross-references our contractual obligations as ofDecember 31, 2019 . This summary indicates on- and off-balance-sheet obligations as ofDecember 31, 2019 . Payments Due by Year More than 5 Total Less than 1 Year 1-3 Years 3-5 Years Years On-Balance Sheet (in millions) Long-term debt(a)$ 4,977 $ 100$ 4,733 $ 144 $ - Interest on long-term debt(b) 988 398 573 17 - Asset retirement obligations(c) 517 28 - - 489 Pension and postretirement 183 13 18 18 134 Operating and finance leases(d) 92 33 21 15 23 Other long-term liabilities 6 2 4 - - Off-Balance Sheet Purchase obligations(e) 153 88 24 19 22 Total$ 6,916 $ 662$ 5,373 $ 213 $ 668
(a) In performing the calculation, the 2014 Revolving Credit Facility borrowings
outstanding at December 31, 2019 of $518 million were assumed to be
outstanding for the entire term of the agreement. See Part II, Item 8 -
Financial Statements and Supplementary Data, Note 6 Debt for more
information.
(b) The calculation of cash interest payments on our variable interest-rate debt
assumes the interest rate at
term and no settlement payments will be received under our interest-rate cap
agreements.
(c) Represents the estimated future asset retirement obligations on a discounted
basis. We do not show the long-term asset retirement obligations by year as
we are not able to precisely predict the timing of these amounts. Because
these costs typically extend many years into the future, estimating these
future costs requires management to make estimates and judgments that are
subject to revisions based on numerous factors, including the rate of
inflation, changing technology, and changes to federal, state and local laws
and regulations. See Part II, Item 8 - Financial Statements and
Supplementary Data, Note 1 Nature of Business, Summary of Significant
Accounting Policies and Other for more information.
(d) Our operating leases include drilling rigs, commercial office space, fleet
vehicles and certain facilities. Our finance leases include information
technology equipment and are not material to our consolidated financial
statements taken as a whole.
(e) Amounts include payments that will become due under long-term agreements to
purchase goods and services used in the normal course of business primarily
including pipeline capacity and land easements. Purchase obligations for
pipeline capacity are based on contractual volumes and our internal estimate
of future prices during the contract period. Land easements include
obligations for fixed payments under our term contracts, and those held by
production cannot be reliably estimated.
Lawsuits, Claims, Commitments and Contingencies
We are involved, in the normal course of business, in lawsuits, environmental and other claims and other contingencies that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief. We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances atDecember 31, 2019 and 2018 were not material to our consolidated balance sheets as of such dates. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves would not be material to our consolidated financial position or results of operations.
See Part II, Item 8 - Financial Statements and Supplementary Data, Note 8 Lawsuits, Claims, Commitments and Contingencies. Critical Accounting Policies and Estimates
Our critical accounting policies and estimates include property, plant and
equipment and fair value measurements. See Part II, Item 8 - Financial
Statements and Supplementary Data, Note 1 Nature of Business, Summary of
Significant Accounting Policies and Other for details on these critical
accounting policies and estimates that involve management's judgment and that
could result in a material impact to the consolidated financial statements due
to the levels of subjectivity and judgment.
65
--------------------------------------------------------------------------------Significant Accounting and Disclosure Changes
See Part II, Item 8 - Financial Statements and Supplementary Data, Note 2 Accounting and Disclosure Changes for a discussion of new accounting standards.
66
--------------------------------------------------------------------------------
FORWARD-LOOKING STATEMENTS
The information included herein contains forward-looking statements that involve
risks and uncertainties that could materially affect our expected results of
operations, liquidity, cash flows and business prospects. Such statements
include those regarding our expectations as to our future:
• financial position, liquidity, cash flows and results of operations
• business prospects
• transactions and projects
• operating costs
• Value Creation Index (VCI) metrics, which are based on certain estimates
including future production rates, costs and commodity prices
• operations and operational results including production, hedging and
capital investment
• budgets and maintenance capital requirements
• reserves • type curves
• expected synergies from acquisitions and joint ventures
Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. While we believe assumptions or bases underlying our expectations are reasonable and make them in good faith, they almost always vary from actual results, sometimes materially. We also believe third-party statements we cite are accurate but have not independently verified them and do not warrant their accuracy or completeness. Factors (but not necessarily all the factors) that could cause results to differ include:
• commodity price changes
• debt limitations on our financial flexibility
• insufficient cash flow to fund planned investments, debt repurchases or
changes to our capital plan
• inability to enter desirable transactions including acquisitions, asset
sales and joint ventures
• legislative or regulatory changes, including those related to drilling,
completion, well stimulation, operation, inspection, maintenance or
abandonment of wells or facilities, managing energy, water, land,
greenhouse gases or other emissions, protection of health, safety and the
environment, or transportation, marketing and sale of our products• joint ventures and acquisitions and our ability to achieve expected synergies
• the recoverability of resources and
unexpected geologic conditions
• incorrect estimates of reserves and related future cash flows and the
inability to replace reserves
• changes in business strategy
• PSC effects on production and unit production costs
• effect of stock price on costs associated with incentive compensation
• insufficient capital or liquidity, including as a result of lender
restrictions, unavailability of capital markets or inability to attract
potential investors
• effects of hedging transactions
• equipment, service or labor price inflation or unavailability
• availability or timing of, or conditions imposed on, permits and approvals
• lower-than-expected production, reserves or resources from development
projects, joint ventures or acquisitions, or higher-than-expected decline
rates
• disruptions due to accidents, mechanical failures, power outages,
transportation or storage constraints, natural disasters, pandemics, labor
difficulties, cyber attacks or other catastrophic events
• factors discussed in Part I, Item 1A - Risk Factors.
Words such as "anticipate," "believe," "continue," "could," "estimate,"
"expect," "goal," "intend," "likely," "may," "might," "plan," "potential,"
"project," "seek," "should," "target, "will" or "would" and similar words that
reflect the prospective nature of events or outcomes typically identify
forward-looking statements. Any forward-looking statement speaks only as of the
date on which such statement is made, and we undertake no obligation to correct
or update any forward-looking statement, whether as a result of new information,
future events or otherwise, except as required by applicable law.
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