OCCIDENTAL PETROLEUM CORP /DE/
ITEM 1A RISK FACTORS
Volatile global and local commodity pricing strongly affects Occidental’s results of operations.
Occidental’s financial results correlate closely to the prices it obtains for its products, particularly oil and, to a lesser extent, natural gas and NGLs, and its chemical products.
Changes in consumption patterns, global and local (particularly for gas) economic conditions, inventory levels, production disruptions, the actions of OPEC, currency exchange rates, worldwide drilling and exploration activities, technological developments, weather, geophysical and technical limitations, transportation bottlenecks and other matters affect the supply and demand dynamics of oil, gas and NGLs, which, along with the effect of changes in market perceptions, contribute to price unpredictability and volatility.
The prices obtained for Occidental’s chemical products correlate strongly to the health of the United States and global economies, as well as chemical industry expansion and contraction cycles. Occidental also depends on feedstocks and energy to produce chemicals, which are commodities subject to significant price fluctuations.
Occidental's potential restructuring activities may affect its stock price.
Occidental has disclosed that it is performing a strategic review of its operations, which may result in a restructuring of its business activities. The outcome of this activity may affect the market value of Occidental's common stock. For example, Occidental may take different
actions than expected, receive less proceeds or retain more liabilities than anticipated in connection with any divestitures. Additionally, the restructuring activity may be viewed negatively by the market and result in a stock price drop.
Occidental may experience delays, cost overruns, losses or other unrealized expectations in development efforts and exploration activities.
Occidental bears the risks of equipment failures, construction delays, escalating costs or competition for services, materials, supplies or labor, property or border disputes, disappointing drilling results or reservoir performance and other associated risks that may affect its ability to profitably grow production, replace reserves and achieve its targeted returns.
Exploration is inherently risky and is subject to delays, misinterpretation of geologic or engineering data, unexpected geologic conditions or finding reserves of disappointing quality or quantity, which may result in significant losses.
Governmental actions and political instability may affect Occidental’s results of operations.
Occidental’s businesses are subject to the decisions of many federal, state, local and foreign governments and political interests. As a result, Occidental faces risks of:
Ø
new or amended laws and regulations, or interpretations of such laws and regulations, including those related to drilling, manufacturing or production processes (including well stimulation techniques such as hydraulic fracturing and acidization), labor and employment, taxes, royalty rates, permitted production rates, entitlements, import, export and use of raw materials, equipment or products, use or increased use of land, water and other natural resources, safety, security and environmental protection, all of which may restrict or prohibit activities of Occidental or its contractors, increase Occidental's costs or reduce demand for Occidental's products;
Ø
refusal of, or delay in, the extension or grant of exploration, development or production contracts; and
Ø
development delays and cost overruns due to approval delays for, or denial of, drilling and other permits.
Occidental may experience adverse consequences, such as risk of loss or production limitations, because certain of its international operations are located in countries occasionally affected by political instability, nationalizations, corruption, armed conflict, terrorism, insurgency, civil unrest, security problems, labor unrest, OPEC production restrictions, equipment import restrictions and sanctions. Exposure to such risks may increase if a greater percentage of Occidental’s future oil and gas production or revenue comes from international sources.
Occidental's oil and gas business operates in highly competitive environments, which affect, among other things, its ability to make acquisitions to grow production and replace reserves.
Results of operations, reserves replacement and growth in oil and gas production depend, in part, on Occidental’s ability to profitably acquire additional reserves. Occidental has many competitors (including national oil companies), some of which: (i) are larger and better funded, (ii) may be willing to accept greater risks or (iii) have special competencies. Competition for reserves may make it more difficult to find attractive investment opportunities or require delay of reserve replacement efforts. In addition, during periods of low product prices, any cash conservation efforts may delay production growth and reserve replacement efforts.
Occidental’s acquisition activities also carry risks that it may: (i) not fully realize anticipated benefits due to less-than-expected reserves or production or changed circumstances, such as the deterioration of natural gas prices in recent years; (ii) bear unexpected integration costs or experience other integration difficulties; (iii) experience share price declines based on the market’s evaluation of the activity; or (iv) assume liabilities that are greater than anticipated.
Occidental’s oil and gas reserves are based on professional judgments and may be subject to revision.
Reported oil and gas reserves are an estimate based on periodic review of reservoir characteristics and recoverability, including production decline rates, operating performance and economic feasibility at the prevailing commodity prices as well as capital and operating costs. If Occidental were required to make significant negative reserve revisions, its results of operations and stock price could be adversely affected.
Concerns about climate change may affect Occidental’s operations.
The U.S. federal government and the state of California have adopted, and other jurisdictions are considering, legislation, regulations or policies that seek to control or reduce the production, use or emissions of “greenhouse gases” (GHG), to control or reduce the production or consumption of fossil fuels, and to increase the use of renewable or alternative energy sources. For example, California’s GHG cap-and-trade program currently applies to Occidental's operations in the state. The U.S. Environmental Protection Agency has begun to regulate certain GHG emissions from both stationary and mobile sources. The uncertain outcome and timing of existing and proposed international, national and state measures make it difficult to predict their business impact. However, Occidental could face risks of project execution, increased costs and taxes and lower demand for and restrictions or prohibition on the use of its products as a result of ongoing GHG reduction efforts.
Occidental’s businesses may experience catastrophic events.
The occurrence of events, such as earthquakes, hurricanes, floods, droughts, well blowouts, fires, explosions, chemical releases, industrial accidents, physical attacks and other events that cause operations to cease or be curtailed, may negatively affect Occidental’s businesses and the communities in which it operates. Third-party insurance may not provide adequate coverage or Occidental may be self-insured with respect to the related losses.
Cyber attacks could significantly affect Occidental.
Cyber attacks on businesses have escalated in recent years. Occidental relies on electronic systems and networks to control and manage its oil and gas, chemicals, trading and pipeline operations and has multiple layers of security to mitigate risks of cyber attack. If, however, Occidental were to experience an attack and its security measures failed, the potential consequences to its businesses and the communities in which it operates could be significant.
Occidental's oil and gas reserve additions may not continue at the same rate and its measure of full cycle cash margin may not be fully comparable to that of other companies.
Management expects improved recovery, extensions and discoveries to continue as main sources for reserve additions but factors, such as geology, government regulations and permits and the effectiveness of development plans, are partially or fully outside management's control and could cause results to differ materially from expectations. Occidental uses a measure referred to as full cycle cash margin to measure its performance in developing reserves at a profitable cost. The measure may not include all the costs associated with exploration and development related to reserves added for the period, or may include costs related to reserves added or to be added in other periods, and may differ from the calculations used by other companies.
Other risk factors.
Additional discussion of risks and uncertainties related to price and demand, litigation, environmental matters, oil and gas reserves estimation processes, impairments, derivatives, market risks and internal controls appears under the headings: "MD&A - Oil & Gas Segment - Proved Reserves" and "- Industry Outlook," "- Chemical Segment - Industry Outlook," "- Midstream and Marketing Segment - Industry Outlook," "- Lawsuits, Claims and Contingencies," "- Environmental Liabilities and Expenditures," "- Critical Accounting Policies and Estimates," "- Derivative Activities and Market Risk," and "Management's Annual Assessment of and Report on Internal Control Over Financial Reporting."
The risks described in this report are not the only risks facing Occidental and other risks, including risks deemed immaterial, may have material adverse effects.
ITEM 1B
UNRESOLVED STAFF COMMENTS
Occidental has no unresolved SEC staff comments that have been outstanding more than 180 days at December 31, 2013.
ITEM 3 LEGAL PROCEEDINGS
The California Air Resources Board asserted a claim dated July 23, 2013, against an OPC subsidiary regarding reporting and emissions from four pieces of equipment at its facility in Long Beach, California. The subsidiary is evaluating the claim. Although this matter is a reportable
event, the financial impact is expected to be insignificant.
For information regarding other legal proceedings, see the information under the caption "Lawsuits, Claims and Other Contingencies" in the MD&A section of this report and in Note 9 to the Consolidated Financial Statements.
ITEM 4 MINE SAFETY DISCLOSURES
Not applicable.
EXECUTIVE OFFICERS
The current term of employment of each executive officer of Occidental will expire at the May 2, 2014, organizational meeting of the Board of Directors or when a successor is selected. The following table sets forth the executive officers of Occidental:
Name
Age at
March 3, 2014
Positions with Occidental and Subsidiaries and Employment History
Stephen I. Chazen
Chief Executive Officer since 2011 and President since 2007; 2010-2011, Chief Operating Officer; 1999-2010, Chief Financial Officer; Director since 2010.
William E. Albrecht
Vice President since 2008; Occidental Oil and Gas Corporation (OOGC): President - Oxy Oil & Gas, Americas since 2011; OOGC: President - Oxy Oil & Gas, USA 2008-2011.
Edward A. "Sandy" Lowe
Vice President since 2008; OOGC: President - Oxy Oil & Gas, International Production since 2009; 2008-2009, Executive Vice President - Oxy Oil & Gas, International Production and Engineering.
Willie C.W. Chiang
Executive Vice President, Operations since 2012; ConocoPhillips: 2011-2012, Senior Vice President, Refining, Marketing, Transportation and Commercial; 2008-2011, Senior Vice President, Refining, Marketing and Transportation.
Vicki A. Hollub
Vice President since 2013; OOGC: Executive Vice President - Oxy Oil & Gas, U.S. Operations since 2013; 2012-2013, Executive Vice President - Oxy Oil & Gas, California Operations; 2011-2012, President & General Manager of Oxy Permian CO2; 2009-2011, Operations Manager of Oxy Permian.
B. Chuck Anderson
Vice President since 2012; President of Occidental Chemical Corporation since 2006.
Cynthia L. Walker
Executive Vice President and Chief Financial Officer since 2012; Goldman, Sachs & Co.: 2010-2012, Managing Director; 2005-2010, Vice President.
James M. Lienert
Executive Vice President - Business Support since 2012; 2010-2012, Executive Vice President and Chief Financial Officer; 2006-2010, Executive Vice President - Finance and Planning.
Marcia E. Backus
Vice President and General Counsel since 2013; Vinson & Elkins: 1990-2013, Partner.
Roy Pineci
Vice President, Controller and Principal Accounting Officer since 2008.
Donald P. de Brier
Corporate Executive Vice President and Corporate Secretary since 2012; 1993-2012, Executive Vice President, General Counsel and Secretary.
Part II
ITEM 5
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
TRADING PRICE RANGE AND DIVIDENDS
This section incorporates by reference the quarterly financial data appearing under the caption "Quarterly Financial Data (Unaudited)" after the Notes to the Consolidated Financial Statements, and the information appearing under the caption "Liquidity and Capital Resources" in the MD&A section of this report. Occidental’s common stock was held by approximately 30,000 stockholders of record at December 31, 2013, and by approximately 648,000 additional stockholders whose shares were held for them in street name or nominee accounts. The common stock is listed and traded on the New York Stock Exchange. The quarterly financial data set forth the range of trading prices for the common stock as reported on the composite tape of the New York Stock Exchange and quarterly dividend information.
The quarterly dividends declared on the common stock were $0.64 for each quarter of 2013 ($2.56 for the year). On February 13, 2014, a quarterly dividend of $0.72 per share was declared on the common stock, payable on April 15, 2014 to stockholders of record on March 10, 2014. The declaration of future dividends is a business decision made by the Board of Directors from time to time, and will depend on Occidental’s financial condition and other factors deemed relevant by the Board.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
All of Occidental's stock-based compensation plans for its employees and non-employee directors have been approved by the stockholders. The aggregate number of shares of Occidental common stock authorized for issuance under such plans is approximately 66 million, of which approximately 16 million had been issued through December 31, 2013. The following is a summary of the securities available for issuance under such plans:
a)
Number of securities to be issued upon exercise of outstanding options, warrants and rights
b)
Weighted-average exercise price of outstanding options, warrants and rights
c)
Number of securities remaining available for future issuance under equity compensation plans (excluding securities in column (a))
2,048,695 (1)
42.11 (2)
19,564,605 (3)
(1)
Includes shares reserved to be issued pursuant to stock options (Options), stock appreciation rights (SARs) and performance-based awards. Shares for performance-based awards are included assuming maximum payout, but may be paid out at lesser amounts, or not at all, according to achievement of performance goals.
(2)
Price applies only to the Options and SARs included in column (a). Exercise price is not applicable to the other awards included in column (a).
(3)
A plan provision requires each share covered by an award (other than Options and SARs) to be counted as if three shares were issued in determining the number of shares that are available for future awards. Accordingly, the number of shares available for future awards may be less than the amount shown depending on the type of award granted. Additionally, under the plan, the amount shown may increase, depending on the award type, by the number of shares currently unvested or forfeitable, or three times that number as applicable, that (i) fail to vest, (ii) are forfeited or canceled, or (iii) correspond to the portion of any stock-based awards settled in cash.
SHARE REPURCHASE ACTIVITIES
Occidental’s share repurchase activities for the year ended December 31, 2013, were as follows:
Period
Total
Number
of Shares
Purchased
Average
Price
Paid
per Share
Total Number of Shares Purchased as Part of Publicly Announced
Plans or Programs
Maximum Number of Shares that May Yet Be Purchased Under the
Plans or Programs
First Quarter 2013
-
$
-
-
Second Quarter 2013
239,444
(a)
$
90.23
-
Third Quarter 2013
410,000
$
87.28
410,000
October 1-31, 2013
669,309
(a)
$
95.29
557,168
November 1-30, 2013
3,870,000
$
96.91
3,870,000
December 1-31, 2013
5,452,239
$
93.10
5,452,239
Fourth Quarter 2013
9,991,548
$
94.72
9,879,407
Total 2013
10,640,992
$
94.34
10,289,407
6,966,168 (b)
(a)
Includes purchases from the trustee of Occidental's defined contribution savings plan that are not part of publicly announced plans or programs.
(b)
Represents the number of shares remaining at year-end under Occidental's share repurchase program of 95 million. In February 2014, Occidental increased the number of shares authorized for its program by 30 million; however, the program does not obligate Occidental to acquire any specific number of shares and may be discontinued at any time.
PERFORMANCE GRAPH
The following graph compares the yearly percentage change in Occidental’s cumulative total return on its common stock with the cumulative total return of the Standard & Poor's 500 Stock Index (S&P 500) and with that of Occidental’s current and prior peer groups over the five-year period ended on December 31, 2013. The graph assumes that $100 was invested at the beginning of the five-year period shown in the graph below in (i) Occidental common stock, (ii) the stock of the companies in the S&P 500 and (iii) each of the current and prior peer group companies' common stock weighted by their relative market values within the respective peer groups, and that all dividends were reinvested.
In 2013, Occidental revised its peer group (which includes Occidental) to ensure the companies continue to provide appropriate comparability to Occidental. Prior to the revision, Occidental's peer group consisted of Anadarko Petroleum Corporation, Apache Corporation, Canadian Natural Resources Limited, Chevron Corporation, ConocoPhillips, Devon Energy Corporation, EOG Resources Inc., ExxonMobil Corporation, Hess Corporation, Royal Dutch Shell plc, Total S.A. and Occidental. Occidental's current peer group consists of Anadarko Petroleum Corporation, Apache Corporation, Canadian Natural Resources Limited, Chevron Corporation, ConocoPhillips, Devon Energy Corporation, EOG Resources Inc., ExxonMobil Corporation, Hess Corporation, Marathon Oil Corporation, Total S.A. and Occidental.
12/31/2008
12/31/2009
12/31/2010
12/31/2011
12/31/2012
12/31/2013
$
$
$
$
$
$
The information provided in this Performance Graph shall not be deemed "soliciting material" or "filed" with the Securities and Exchange Commission or subject to Regulation 14A or 14C under the Exchange Act, other than as provided in Item 201 to Regulation S-K under the Exchange Act, or subject to the liabilities of Section 18 of the Exchange Act and shall not be deemed incorporated by reference into any filing under the Securities Act of 1933 or the Exchange Act except to the extent Occidental specifically requests that it be treated as soliciting material or specifically incorporates it by reference.
_______________________
(1)
The cumulative total return of the peer group companies' common stock includes the cumulative total return of Occidental's common stock.
ITEM 6
SELECTED FINANCIAL DATA
FIVE-YEAR SUMMARY OF SELECTED FINANCIAL DATA
Dollar amounts in millions, except per-share amounts
As of and for the years ended December 31,
RESULTS OF OPERATIONS (a)
Net sales
$
24,455
$
24,172
$
23,939
$
19,045
$
14,814
Income from continuing operations
$
5,922
$
4,635
$
6,640
$
4,569
$
3,151
Net income attributable to common stock
$
5,903
$
4,598
$
6,771
$
4,530
$
2,915
Basic earnings per common share from continuing operations
$
7.35
$
5.72
$
8.16
$
5.62
$
3.88
Basic earnings per common share
$
7.33
$
5.67
$
8.32
$
5.57
$
3.59
Diluted earnings per common share
$
7.32
$
5.67
$
8.32
$
5.56
$
3.58
FINANCIAL POSITION (a)
Total assets
$
69,443
$
64,210
$
60,044
$
52,432
$
44,229
Long-term debt, net
$
6,939
$
7,023
$
5,871
$
5,111
$
2,557
Stockholders’ equity
$
43,372
$
40,048
$
37,620
$
32,484
$
29,159
MARKET CAPITALIZATION (b)
$
75,699
$
61,710
$
75,992
$
79,735
$
66,050
CASH FLOW
Operating:
Cash provided by operating activities
$
12,927
$
11,312
$
12,281
$
9,566
$
5,946
Investing:
Capital expenditures
$
(9,037
)
$
(10,226
)
$
(7,518
)
$
(3,940
)
$
(3,245
)
Cash provided (used) by all other investing activities, net
$
$
(2,429
)
$
(2,385
)
$
(5,355
)
$
(2,221
)
Financing:
Cash dividends paid
$
(1,553
)
(c)
$
(2,128
)
(c)
$
(1,436
)
$
(1,159
)
$
(1,063
)
Cash (used) provided by all other financing activities, net
$
(1,380
)
$
1,282
$
$
2,242
$
DIVIDENDS PER COMMON SHARE
$
2.56
$
2.16
$
1.84
$
1.47
$
1.31
WEIGHTED AVERAGE BASIC SHARES OUTSTANDING (thousands)
804,064
809,345
812,075
812,472
811,305
Note: Argentine operations were sold in February 2011 and have been reflected as discontinued operations for all applicable periods.
(a)
See the MD&A section of this report and the Notes to Consolidated Financial Statements for information regarding acquisitions and dispositions, discontinued operations and other items affecting comparability.
(b)
Market capitalization is calculated by multiplying the year-end total shares of common stock outstanding, net of shares held as treasury stock, by the year-end closing stock price.
(c)
The 2012 amount includes an accelerated fourth quarter dividend payment, which normally would have been accrued as of year-end 2012 and paid in the first quarter of 2013.
ITEM 7 AND 7A
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)
In this report, "Occidental" means Occidental Petroleum Corporation (OPC), or OPC and one or more entities in which it owns a controlling interest (subsidiaries). Occidental's principal businesses consist of three segments operated by OPC's subsidiaries and affiliates. The oil and gas segment explores for, develops and produces oil and condensate, natural gas liquids (NGL) and natural gas. The chemical segment (OxyChem) mainly manufactures and markets basic chemicals and vinyls. The
midstream, marketing and other segment (midstream and marketing) gathers, processes, transports, stores, purchases and markets oil, condensate, NGLs, natural gas, carbon dioxide (CO2) and power. It also trades around its assets, including transportation and storage capacity, and trades oil, NGLs, gas and other commodities. Additionally, the midstream and marketing segment invests in entities that conduct similar activities.
STRATEGY
General
Through its operations, Occidental aims to maximize total returns to stockholders using the following strategies:
Ø
Grow oil and gas segment production through development programs focused on large, long-lived conventional and unconventional oil and gas assets with long-term growth potential, and acquisitions;
Ø
Allocate and deploy capital with a focus on achieving returns well in excess of Occidental's cost of capital;
Ø
Provide consistent dividend growth; and
Ø
Maintain financial discipline and a strong balance sheet.
In conducting its business, Occidental accepts commodity, engineering and limited exploration risks. Occidental seeks to limit its financial and political risks.
To maximize returns, Occidental from time to time reviews its business strategy. In October 2013 and February 2014, Occidental’s Board of Directors authorized several actions resulting from a strategic review to streamline and focus operations in order to better execute Occidental’s long-term strategy and enhance value for shareholders. The authorized actions included:
Ø
Pursue the sale of a minority interest in the Middle East/North Africa operations in a financially efficient manner.
Ø
Pursue strategic alternatives for select Midcontinent assets, including oil and gas interests in the Williston Basin, Hugoton Field, Piceance Basin and other Rocky Mountain assets.
Ø
Pursue the sale of a portion of Occidental’s investment in the General Partner of Plains All-American Pipeline, L.P. (Plains Pipeline).
Ø
Separation of its California assets into an independent and separately traded company.
With respect to these initiatives, since October, Occidental:
Ø
Sold a portion of Plains Pipeline, while continuing to hold an approximate 25-percent interest;
Ø
Made steady progress on discussions with key partners in countries where Occidental operates in the Middle East/North Africa region for the sale of a minority interest in its operations there; and
Ø
Entered into an agreement to sell its Hugoton operations.
The strategic review underway is expected to result in significant changes to Occidental’s asset mix. Occidental's capital program, production expectations and other elements of its future plans will be adjusted as related transactions are concluded. Proceeds resulting from these actions will largely be used to reduce Occidental's capitalization. In the fourth quarter of 2013 Occidental bought back almost 10 million shares of its own stock for approximately $0.9 billion using the proceeds from the
Plains Pipeline sale. Occidental also retired $0.6 billion of its debt in the fourth quarter.
Occidental prioritizes the use of its operating cash flows in the following order:
Ø
Base/Maintenance capital
Ø
Dividends
Ø
Growth capital
Ø
Share repurchases
Ø
Acquisitions
Capital is employed to operate all assets in a safe and environmentally sound manner. Management aims to develop Occidental's assets in a manner that would contribute substantially to earnings and cash flow after invested capital. The following describes the application of Occidental's overall strategy to each of its operating segments.
Oil and Gas
Segment Earnings
($ millions)
Occidental prefers to hold large, long-lived "legacy" oil and gas assets, like those in California and the Permian Basin, that tend to have enhanced secondary and tertiary recovery opportunities and economies of scale that lead to cost-effective production. Occidental also focuses a growing portion of its drilling activities on unconventional shale opportunities.
The oil and gas business seeks to increase its oil and gas production profitably and add new reserves at a pace ahead of production while minimizing costs incurred for finding and development of such reserves. The oil and gas business implements this strategy within the limits of the overall corporate strategy primarily by:
Ø
Deploying capital efficiently to fully develop areas where reserves are known to exist and increase production from mature and underdeveloped fields and from unconventional acreage by applying appropriate technology and advanced reservoir-management practices;
Ø
Adding reserves through a combination of focused exploration and development programs conducted in Occidental's core areas, primarily in the United States but also in the Middle East/North Africa and Latin America; and
Ø
Maintaining a disciplined approach to acquisitions and divestitures with an emphasis on transactions at attractive prices.
Over the past several years, Occidental built a large portfolio of growth-oriented assets in the United States. In 2013, Occidental spent a much larger portion of its investment capital on the development of this portfolio. Acquisitions in 2013 were at a multi-year low of approximately $0.5 billion, all for domestic oil and gas properties. Compared to recent years, this reduced acquisition activity reflects Occidental's strategy to capitalize on the opportunities presented by its existing portfolio of assets.
Management currently believes Occidental's oil and gas segment growth will come domestically from higher oil production in California and the Permian Basin, and internationally from opportunities in key assets, mainly in Oman and Qatar, as well as the completion of the Al Hosn gas project in late 2014.
Chemical
Segment Earnings
($ millions)
The primary objective of the chemical business (OxyChem) is to generate cash flow in excess of its normal capital expenditure requirements and achieve above-cost-of-capital returns. The chemical segment's strategy is to be a low-cost producer in order to maximize its cash flow generation. OxyChem concentrates on the chlorovinyls chain beginning with chlorine, which is co-produced with caustic soda, and markets both to third parties. In addition, chlorine, together with ethylene, is converted through a series of intermediate products into PVC. OxyChem's focus on chlorovinyls allows it to maximize the benefits of integration and take advantage of economies of scale. Capital is employed to sustain production capacity and to
focus on projects and developments designed to improve the competitiveness of segment assets. Acquisitions and plant development opportunities may be pursued when they are expected to enhance the existing core chlor-alkali and PVC businesses or take advantage of other specific opportunities. OxyChem expects to begin operating the New Johnsonville, Tennessee chlor-alkali facility in early 2014. During the second quarter of 2013, Occidental sold its investment in Carbocloro, a Brazilian joint venture, for a pre-tax gain of $131 million. In the fourth quarter of 2013, OxyChem and Mexichem, S.A.B. de C.V. formed a 50/50 joint venture to construct and operate a 1.2-billion-pound per year capacity ethylene cracker with startup expected in 2017, and entered into related supply agreements.
Midstream and Marketing
Segment Earnings
($ millions)
The midstream and marketing segment strives to maximize realized value by optimizing use of its assets, including its transportation and storage capacity, and by providing access to multiple markets. In order to generate returns, the segment evaluates opportunities across the value chain and uses its assets to provide services to other Occidental segments as well as third parties. In commodities trading, Occidental seeks to generate gains using net-long positions. The segment invests in and operates gas plants, co-generation facilities, pipeline systems and storage facilities. The segment also seeks to minimize the costs of gas, power and other commodities used in Occidental's businesses and to limit credit risk exposure. Capital is employed to sustain or, where appropriate, increase operational and transportation capacity and to improve the competitiveness of Occidental's assets. Occidental and Magellan Midstream Partners, L.P. (Magellan) are proceeding with the construction of the BridgeTex Pipeline, which will transport crude oil between the Permian region and the Gulf Coast refinery markets and is expected to begin service in mid-2014. In 2013, Occidental completed the sale of a portion of its investment in Plains Pipeline, resulting in a $1.0 billion pre-tax gain.
Key Performance Indicators
General
Occidental seeks to meet its strategic goals by continually measuring its success in its key performance metrics that drive total stockholder return. In addition to production growth and capital allocation and deployment discussed above, Occidental believes the following are its most significant metrics:
Ø
Cash margin per barrel;
Ø
Free-cash-flow yield;
Ø
Dividend growth;
Ø
Return on equity (ROE) and return on capital employed (ROCE);
Ø
Full cycle cash margin.
Occidental also monitors other segment-specific indicators such as per-unit profit, production costs and finding and development costs, as well as health, environmental and safety measures such as the number of recordable injuries, and others.
Based on the $2.88 per share annual dividend rate announced in February 2014, Occidental’s dividend rate has increased by 476 percent since 2002. While its stockholders' equity increased by 8 percent for 2013 and 34 percent for the three-year period from 2011 through 2013, Occidental continued to deliver above-cost-of-capital returns as follows:
Annual 2013 (a)
Three-Year Annual
Average 2011 - 2013 (b)
ROE
14.2%
15.0%
{13.3%}
ROCE
12.2%
13.1%
{11.5%}
(a)
The top figures were calculated by dividing Occidental's 2013 net income (adding back after-tax interest expense for ROCE) by its average equity (using debt and equity for ROCE) during 2013. The bottom figures were calculated in the same manner as the top figures, except that they exclude the effects of Significant Items Affecting Earnings described on page 25. We provide this adjusted measure because we believe it would be useful to investors in evaluating and comparing Occidental's performance between periods, not as a substitute for the measure calculated using net income.
(b)
The three-year averages were calculated by dividing Occidental's average net income (adding back after-tax interest expense for ROCE) over the three-year period by its average equity (using debt and equity for ROCE) over the same period.
Full cycle cash margin (a)
$
34.16
$
21.28
(a)
Amounts were calculated by subtracting operating costs, taxes other than on income and general and administrative expenses for producing operations, all on a per BOE basis, from realized price for the year. Subtracted from this amount is the finding and development costs per BOE, calculated by dividing exploration and development costs incurred, including asset retirement obligations, but excluding acquisition costs, by proved reserve additions for the year from improved recovery, extensions, discoveries and revisions. Reserve additions include proved undeveloped reserves, for which estimated future development costs are included in amounts disclosed in the Supplemental Oil and Gas Information - Standardized Measure of Discounted Future Net Cash Flows.
Debt Structure
In 2013, Occidental decreased its debt balance by $690 million, which reduced its debt-to-capitalization (debt and equity) ratio from 16 percent at year-end 2012 to 14 percent at year-end 2013.
OIL AND GAS SEGMENT
Business Environment
Oil and gas prices are the major variables that drive the industry’s short- and intermediate-term financial performance. The following table presents the average daily West Texas Intermediate (WTI), Brent and New York Mercantile Exchange (NYMEX) prices for 2013 and 2012:
WTI oil ($/barrel)
$
97.97
$
94.21
Brent oil ($/barrel)
$
108.76
$
111.70
NYMEX gas ($/Mcf)
$
3.66
$
2.81
The following table presents Occidental's average realized prices as a percentage of WTI, Brent and NYMEX for 2013 and 2012:
Worldwide oil as a percentage of average WTI
%
%
Worldwide oil as a percentage of average Brent
%
%
Worldwide NGLs as a percentage of average WTI
%
%
Domestic natural gas as a percentage of NYMEX
%
%
Average worldwide realized oil prices were flat in 2013 compared to 2012. Approximately 60 percent of Occidental’s oil production tracks world oil prices, such as Brent, and 40 percent tracks WTI. The average realized domestic natural gas price in 2013 increased 29 percent from 2012.
Prices and differentials can vary significantly, even on a short-term basis, making it impossible to predict realized prices with a reliable degree of certainty.
Operations
Domestic Interests
Occidental conducts its domestic operations through land leases, subsurface mineral rights it owns or a combination of both surface land and subsurface mineral rights it owns. Occidental's domestic oil and gas leases have a primary term ranging from one to ten years, which is extended through the end of production once it commences. Of the total 8.2 million net acres in which Occidental has interests, approximately 74 percent is leased, 25 percent is owned subsurface mineral rights and 1 percent is owned land with mineral rights.
Production-Sharing Contracts (PSC)
Occidental has interests that are operated under PSCs or similar contracts in Bahrain, Iraq, Libya, Oman, Qatar and Yemen. Under such contracts, Occidental records a share of production and reserves to recover certain production costs and an additional share for profit. In addition, Occidental's share of production and reserves from operations in Long Beach, California, and certain contracts in Colombia are subject to contractual
arrangements similar to a PSC. These contracts do not transfer any right of ownership to Occidental and reserves reported from these arrangements are based on Occidental’s economic interest as defined in the contracts. Occidental’s share of production and reserves from these contracts decreases when product prices rise and increases when prices decline. Overall, Occidental’s net economic benefit from these contracts is greater when product prices are higher.
Business Review
The following chart shows Occidental’s total volumes for the last five years:
Worldwide Production Volumes
(thousands BOE/day)
Notes:
•
Excludes volumes from the Argentine operations sold in 2011 and classified as discontinued operations.
United States Assets
United States
1.
Permian Basin
2.
California
3.
Midcontinent and Other interests
Permian Basin
Occidental's Permian Basin production is diversified across a large number of producing areas. The basin extends throughout southwest Texas and southeast New Mexico and is one of the largest and most active oil basins in the United States, accounting for approximately 15 percent of the total United States oil production. Occidental
is the largest operator and the largest producer of oil in the Permian Basin with an approximate 15 percent net share of the total oil production in the basin. Occidental also produces and processes natural gas and NGLs in the basin.
Occidental manages its Permian Basin operations through two business units: Permian EOR (enhanced oil recovery), which includes CO2 and waterfloods, and Permian Resources, which includes growth-oriented unconventional opportunities. During 2013, capital efficiency efforts reduced drilling costs per well by 25 percent for the Permian Basin operations while operating expenses decreased by $3.22 per barrel, or 17 percent. In addition, management began transitioning to a horizontal drilling program to take advantage of unconventional and shale opportunities. In the Permian Basin, Occidental spent over $1.7 billion of capital in 2013 with 64 percent spent on Permian Resources assets. In 2014, Permian Basin capital spending is expected to be slightly less than $2.2 billion. The entire $450 million increase will be spent on Permian Resources assets and will focus on growing oil production. Approximately 70 percent of the total capital to be spent in the Permian Basin will be for Permian Resources assets.
Occidental's Permian Resources operations are among its fastest-growing assets and held approximately 1.9 million net acres at the end of 2013, including acreage with prospective resource potential. The development program, largely begun in 2010, continued to increase in 2013, accounting for more than 285 wells drilled. In 2013, Permian Resources drilled 49 horizontal wells and expects this to increase in 2014 to approximately 172 of its 345 total planned wells. Production from this business unit comes from approximately 9,500 gross wells, of which 54 percent are operated by other producers. On a net basis, this represents approximately 4,400 wells, of which only 15 percent are operated by others.
The Permian EOR business unit operates a combination of CO2 and waterfloods which have similar development characteristics and ongoing monitoring and maintenance requirements. Approximately 74 percent of Occidental’s Permian EOR oil production is from fields that actively employ CO2 flood technology, an enhanced oil recovery technique. These CO2 flood operations make Occidental a world leader in the application of this technology. Occidental believes it has the ability to accelerate growth in the Permian EOR projects as more CO2 becomes available. Over the past several years, Occidental has focused more capital on waterfloods than CO2 developments. Of the $660 million in capital spending Permian EOR plans for 2014, 25 percent will be used for current waterflood development and the remainder for CO2 floods.
Occidental's share of production in the Permian Basin was approximately 212,000 BOE per day in 2013.
California
Occidental's California operations include interests in the San Joaquin Valley, the Wilmington and other fields in the Los Angeles Basin, and the Ventura and Sacramento Basins. Occidental is California's largest producer of natural gas and the largest oil and gas producer on a gross-
operated-BOE basis and has properties in approximately 130 fields. Occidental manages its California operations through separate teams focused on waterfloods; steam floods for heavy oil resources; and unconventional and other developing plays.
The main California objectives in 2013 were to deliver a predictable outcome, advance low-risk projects that contribute to long-term growth, reduce the cost structure, lower the base decline, create a more balanced portfolio and test exploration and development concepts. Occidental believes it achieved all of these objectives in 2013, notably progressing the development of its multi-year steam floods in Kern Front and Lost Hills, bringing its Huntington Beach Field waterflood redevelopment online, further developing its Wilmington Field, improving capital efficiency by 20 percent and reducing operating costs by $4.70 per BOE, or 20 percent.
Occidental increased the 2013 oil development capital spending to almost 90 percent of the total capital for California. Of the $1.5 billion of capital spent in 2013, 39 percent was for waterfloods, 22 percent for steam floods and 39 percent for unconventional and other developing plays. The 2014 program will continue efforts in each of these areas with increased efforts in horizontal wells in Occidental's waterfloods, new pilot projects in its steam floods and increased unconventional drilling. The allocation for the $1.9 billion 2014 capital program is expected to be similar to 2013. The 2014 capital strategy is to continue focusing the majority of capital spending on projects identified as low-decline, low-risk, and high-return that are expected to provide long-term growth and capitalize on recent exploration successes. Occidental drilled approximately 770 wells in California during 2013 and plans to drill approximately 1,050 wells in 2014, including 175 waterflood wells in the LA Basin, 420 wells for steam floods and 130 unconventional shale wells at Elk Hills.
Over the next several years, there will be some rebalancing between high-decline, such as Elk Hills, and low-decline assets. With the higher investments in water and steam floods, production from these fields is expected to grow faster. The investments being made in high-decline assets are expected to moderate their decline. As a result, the balance of assets in the California portfolio is expected to shift towards low-decline assets over time.
In addition, Occidental holds more than 2.3 million net acres in California, the large majority of which are net fee mineral interests. As a result, Occidental has a substantial inventory of properties available for future development and exploitation opportunities. Currently, approximately one-third of California production is from unconventional reservoirs and Occidental holds more than 1.1 million net acres for such resources. Occidental's share of production in California was approximately 154,000 BOE per day in 2013.
Midcontinent and Other
The Midcontinent and Other properties include interests in the Hugoton Field, the Piceance Basin, the Williston Basin, and the Eagle Ford Shale and other areas in South Texas. These properties are located in Kansas,
Oklahoma, Colorado, North Dakota and Texas. Occidental holds over 2.3 million net acres in the Midcontinent region, which includes 1.4 million net acres in a large concentration of gas reserves and production and royalty interests in the Hugoton area and approximately 168,000 net acres in the Piceance area. Occidental also holds approximately 176,000 net acres in South Texas, including 4,000 net acres in the Eagle Ford Shale. In addition, Occidental holds approximately 335,000 net acres of oil-producing and unconventional properties in the Williston Basin's Bakken, Three Forks and Pronghorn formations.
In Midcontinent and Other, Occidental drilled approximately 175 wells and produced approximately 108,000 BOE per day in 2013.
Other Developments
During its annual capital planning process in the fourth quarter of 2013, management determined that it would not pursue development of certain of its non-producing domestic oil and gas acreage based on product prices, availability of transportation capacity to market the products and regulatory and environmental considerations. As a result, Occidental recorded pre-tax impairment charges of $0.6 billion for the acreage.
Middle East/North Africa Assets
Middle East/North Africa
1.
Bahrain
2.
Iraq
3.
Libya
4.
Oman
5.
Qatar
6.
United Arab Emirates
7.
Yemen
Bahrain
In 2009, Occidental and other consortium members began operating the Bahrain Field under a 20-year development and production sharing agreement (DPSA). Occidental has a 48-percent working interest in the joint venture. Since handover of operations, the consortium has increased gross gas production capacity more than 50 percent from an initial level of 1.5 billion cubic feet per day to over 2.3 billion cubic feet per day and increased gross oil production from 26,000 barrels per day to 44,000 barrels per day. Occidental's share of production from Bahrain during 2013 was approximately 241 million cubic feet (MMcf) per day of gas and 3,000 barrels of oil per day.
Iraq
In 2010, Occidental and other consortium members signed a 20-year contract with the South Oil Company of Iraq to develop the Zubair Field. In 2013, the terms were improved reflecting a reduction in the targeted production level to 850,000 BOE per day and a five-year extension to 2035. Occidental's interest in this contract entitles Occidental to receive oil for cost recovery and a remuneration fee. Past delays in development plans have limited the amount of production from Iraq. Occidental does not know when development activities will reach desired levels. Occidental's share of production from Iraq was approximately 17,000 BOE per day in 2013.
Libya
Occidental participates with the Libyan National Oil Company in the Sirte Basin producing operations. These agreements continue through 2032. In 2013, production was disrupted for a significant portion of the year due to field and port strikes. Occidental does not know when operations will return to normal levels. The 2013 production volume was approximately 7,000 BOE per day.
Oman
In Oman, Occidental is the operator of Block 9 and Block 27, with a 65-percent working interest in each block; Block 53, with a 45-percent working interest; and Block 62, with a 48-percent working interest.
A 30-year PSC for the Mukhaizna Field (Block 53) was signed with the Government of Oman in 2005, pursuant to which Occidental assumed operation of the field. By the end of 2013, Occidental had drilled more than 2,100 new wells and continued implementation of a major steamflood project. In 2013, the average gross daily production was 123,000 BOE per day, which was over 15 times higher than the production rate in September 2005 when Occidental assumed operations.
The term for Block 9 continues through December 2015, with a 10-year extension right for certain areas, subject to government approval. The term for Block 27 expires in 2035.
In 2008, Occidental was awarded a 20-year contract for Block 62, subject to declaration of commerciality, where it is pursuing development and exploration opportunities targeting gas and condensate resources.
Occidental's share of production from Oman was approximately 74,000 BOE per day in 2013.
Qatar
In Qatar, Occidental is the operator at Idd El Shargi North Dome (ISND) and Idd El Shargi South Dome (ISSD), with a 100-percent working interest in each, and Al Rayyan (Block 12), with a 92.5-percent working interest. The terms for ISND, ISSD and Block 12 expire in 2019, 2022 and 2017, respectively.
In 2013, Occidental received approval from the Government of Qatar for the fifth phase of field development of the ISND Field, intended to improve the ultimate recovery in all existing contract reservoirs by drilling over 200 additional production, water injection and water source wells and installing associated facilities required to support the additional wells. Occidental's aggregate investment is expected to exceed $3 billion through 2019 with the goal of sustaining gross oil production levels at approximately 100,000 barrels per day during that period.
Occidental's Dolphin investment comprises two separate economic interests through which Occidental owns: (i) a 24.5-percent undivided interest in the upstream operations under a DPSA with the Government of Qatar to develop and produce natural gas and NGLs in Qatar’s North Field through mid-2032, with a provision to request a five-year extension; and (ii) a 24.5-percent interest in the stock of Dolphin Energy Limited (Dolphin Energy), which operates a pipeline and is discussed further in "Midstream and Marketing Segment - Pipeline Transportation."
Occidental's share of production from Qatar was approximately 105,000 BOE per day in 2013.
United Arab Emirates
In 2011, Occidental acquired a 40-percent participating interest in the Al Hosn gas project, joining with the Abu Dhabi National Oil Company (ADNOC) in a 30-year joint venture agreement. Once fully operational, the project is anticipated to produce over 500 MMcf per day of natural gas, of which Occidental’s net share would be over 200 MMcf per day. In addition, the project is expected to produce over 50,000 barrels per day of NGLs and condensate, of which Occidental’s net share would be over 20,000 barrels per day. Occidental’s 2013 capital expenditures for this project were approximately $950 million. A substantial portion of the total expenditures to date has been incurred in connection with plants and facilities and is included in the midstream and marketing segment. Occidental believes that its share of total 2014 capital for the project will be approximately $760 million. Initial production from this project is expected to commence in the fourth quarter of 2014.
Occidental conducts a majority of its Middle East business development activities through its office in Abu Dhabi, which also provides various support functions for Occidental’s Middle East/North Africa oil and gas operations.
Yemen
In Yemen, Occidental owns interests in: Block 10 East Shabwa Field, which extends through 2015 with a 40.4-percent interest that includes an 11.8-percent interest held in an unconsolidated entity, and Block S-1 An Nagyah Field, which is an Occidental-operated block with a 75-percent working interest that extends into 2023.
Occidental's share of production from the Yemen properties was approximately 12,000 BOE per day in 2013.
Latin America Assets
Latin America
1. Bolivia
2. Colombia
Bolivia
Occidental holds working interests in the Tarija, Chuquisaca and Santa Cruz regions of Bolivia, which produce gas.
Colombia
Occidental has a working interest in the La Cira-Infantas area and has operations within the Llanos Norte Basin. Occidental's interests range from 39 to 61 percent and certain interests expire between 2023 and 2030, while others extend through the economic limit of the areas. Occidental's share of production was approximately 29,000 BOE per day in 2013.
Proved Reserves
Proved oil, NGL and gas reserves were estimated using the unweighted arithmetic average of the first-day-of-the-month price for each month within the year, unless prices were defined by contractual arrangements. Oil, NGL and gas prices used for this purpose were based on posted benchmark prices and adjusted for price differentials including gravity, quality and transportation costs. For the 2013, 2012 and 2011 disclosures, the calculated average West Texas Intermediate oil prices were $96.94, $94.71 and $96.19 per barrel, respectively. The calculated average Henry Hub gas prices for 2013, 2012 and 2011 disclosures were $3.65, $2.79 and $4.04 per MMBtu, respectively.
Occidental had proved reserves at year-end 2013 of 3,483 million BOE, compared to the year-end 2012 amount of 3,296 million BOE. Proved reserves at year-end 2013 and 2012 consisted of, respectively, 62 percent oil each year, 12 percent and 10 percent NGLs and 26 percent and 28 percent natural gas. Proved developed reserves represented approximately 70 percent and 73 percent, respectively, of Occidental’s total proved reserves at year-end 2013 and 2012. A substantial portion of the proved undeveloped (PUD) reserves as of December 31, 2013, as well as the increase in the share of PUDs in 2013, compared to 2012, was the result of PUDs from the Al Hosn gas project reserves, which represented 27 percent of total year-end
PUDs. Occidental expects to transfer a substantial portion of these reserves to the proved developed category at the end of 2014 when additional wells are drilled and initial production begins in the fourth quarter.
Occidental does not have any reserves from non-traditional sources. For further information regarding Occidental's proved reserves, see "Supplemental Oil and Gas Information" following the "Financial Statements."
Proved Reserve Additions
Occidental's total proved reserve additions from all sources were 470 million BOE in 2013. Over 90 percent of these reserve additions were the result of Occidental's development program.
The total additions were as follows:
In millions of BOE
Improved recovery
Extensions and discoveries
Purchases
Revisions of previous estimates
Total additions
Occidental's ability to add reserves, other than through purchases, depends on the success of improved recovery, extension and discovery projects, each of which depends on reservoir characteristics, technology improvements and oil and natural gas prices, as well as capital and operating costs. Many of these factors are outside management’s control, and will affect whether these historical sources of proved reserve additions continue at similar levels. Occidental's 2013 development program provided approximately 291 million BOE of reserve additions domestically.
Improved Recovery
In 2013, Occidental added proved reserves of 348 million BOE from improved recovery through its EOR and infill drilling activities. Generally, the improved recovery additions in 2013 were associated with the continued development of properties in Permian Basin, California, Williston Basin, Qatar and Oman. These properties comprise both conventional projects, which are characterized by the deployment of EOR development methods, largely employing application of CO2, waterflood or steam flood, and unconventional projects. These types of conventional EOR development methods can be applied through existing wells, though additional drilling is frequently required to fully optimize the development configuration. Waterflooding is the technique of injecting water into the formation to displace the oil to the offsetting oil production wells. The use of either CO2 or steam flooding depends on the geology of the formation, the evaluation of engineering data, availability and cost of either CO2 or steam and other economic factors. Both techniques work similarly to lower viscosity causing the oil to move more easily to the producing wells. Many of Occidental's projects, including unconventional projects, rely on improving permeability to increase flow in the wells. In addition, some improved recovery comes from drilling infill
wells that allow recovery of reserves that would not be recoverable from existing wells.
Extensions and Discoveries
Occidental also added proved reserves from extensions and discoveries, which are dependent on successful exploration and exploitation programs. In 2013, extensions and discoveries added 81 million BOE, substantially all of which is attributable to the recognition of proved undeveloped reserves from the Al Hosn gas project.
Purchases of Proved Reserves
Occidental continues to add reserves through acquisitions when properties are available at prices it deems reasonable. As market conditions change, the available supply of properties may increase or decrease accordingly. In 2013, Occidental added 37 million BOE through purchases of proved reserves largely consisting of several domestic acquisitions in the Permian Basin.
Revisions of Previous Estimates
Revisions can include upward or downward changes to previous proved reserve estimates for existing fields due to the evaluation or interpretation of geologic, production decline or operating performance data. In addition, product price changes affect proved reserves recorded by Occidental. For example, higher prices may increase the economically recoverable reserves, particularly for domestic properties, because the extra margin extends the expected life of the operations. Offsetting this effect, higher prices decrease Occidental's share of proved reserves under PSCs because less oil is required to recover costs. Conversely, when prices drop, Occidental's share of proved reserves increases for PSCs and economically recoverable reserves may drop for other operations. In 2013, revisions of previous estimates provided an increase of 4 million BOE to proved reserves.
Reserve estimation rules require that estimated ultimate recoveries be much more likely to increase or remain constant than to decrease as changes are made due to increased availability of technical data. As a result, apart from the effect of product prices, it is generally more likely that future proved reserve revisions will be positive in aggregate over time rather than negative.
Proved Undeveloped Reserves
In 2013, Occidental had proved undeveloped reserve additions of 363 million BOE from improved recovery, extensions and discoveries and purchases. Of the total additions, 270 million BOE represented additions from improved recovery, primarily in Permian Basin, California, Williston Basin and internationally in Qatar and Oman. Occidental added 15 million BOE through purchases of proved undeveloped reserves domestically in the Permian Basin. Additionally, the proved undeveloped reserves increased due to extensions and discoveries mainly from the Al Hosn gas project. These proved undeveloped reserve additions were offset by transfers of 150 million BOE to the proved developed category as a result of the 2013 development programs. Occidental incurred
approximately $2.7 billion in 2013 to convert proved undeveloped reserves to proved developed reserves. Permian Basin, California, Oman, Williston Basin and South Texas accounted for approximately 88 percent of the reserve transfers from proved undeveloped to proved developed in 2013. While costs to develop proved undeveloped reserves have generally increased over time, in 2013 domestic development costs per barrel decreased by 25 percent as a result of the capital efficiency initiatives. A substantial portion of the PUDs as of December 31, 2013, as well as the increase in the share of PUDs in 2013, compared to 2012, was the result of PUDs from the Al Hosn gas project reserves, which represented 27 percent of total year-end proved undeveloped reserves. Occidental expects to transfer a substantial portion of these reserves to the proved developed category at the end of 2014 when additional wells are drilled and initial production begins in the fourth quarter.
Reserves Evaluation and Review Process
Occidental’s estimates of proved reserves and associated future net cash flows as of December 31, 2013, were made by Occidental’s technical personnel and are the responsibility of management. The estimation of proved reserves is based on the requirement of reasonable certainty of economic producibility and funding commitments by Occidental to develop the reserves. This process involves reservoir engineers, geoscientists, planning engineers and financial analysts. As part of the proved reserves estimation process, all reserve volumes are estimated by a forecast of production rates, operating costs and capital expenditures. Price differentials between benchmark prices (the unweighted arithmetic average of the first-day-of-the-month price for each month within the year) and realized prices and specifics of each operating agreement are then used to estimate the net reserves. Production rate forecasts are derived by a number of methods, including estimates from decline curve analysis, type-curve analysis, material balance calculations that take into account the volumes of substances replacing the volumes produced and associated reservoir pressure changes, seismic analysis and computer simulation of the reservoir performance. These field-tested technologies have demonstrated reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. Operating and capital costs are forecast using the current cost environment applied to expectations of future operating and development activities.
Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods for which the incremental cost of any additional required investment is relatively minor. Net proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
The current Senior Vice President, Reserves for Oxy Oil and Gas is responsible for overseeing the preparation of reserve estimates, in compliance with U.S. Securities and Exchange Commission (SEC) rules and regulations,
including the internal audit and review of Occidental's oil and gas reserves data. The Senior Vice President has over 30 years of experience in the upstream sector of the exploration and production business, and has held various assignments in North America, Asia and Europe. He is a three-time past Chair of the Society of Petroleum Engineers Oil and Gas Reserves Committee. He is an American Association of Petroleum Geologists (AAPG) Certified Petroleum Geologist and currently serves on the AAPG Committee on Resource Evaluation. He is a member of the Society of Petroleum Evaluation Engineers, the Colorado School of Mines Potential Gas Committee and the UNECE Expert Group on Resource Classification. He is also an active member of the Joint Committee on Reserves Evaluator Training (JCORET). The Senior Vice President has Bachelor of Science and Master of Science degrees in geology from Emory University in Atlanta.
Occidental has a Corporate Reserves Review Committee (Reserves Committee), consisting of senior corporate officers, to review and approve Occidental's oil and gas reserves. The Reserves Committee reports to the Audit Committee of Occidental's Board of Directors during the year. Since 2003, Occidental has retained Ryder Scott Company, L.P. (Ryder Scott), independent petroleum engineering consultants, to review its annual oil and gas reserve estimation processes.
In 2013, Ryder Scott conducted a process review of the methods and analytical procedures utilized by Occidental’s engineering and geological staff for estimating the proved reserves volumes, preparing the economic evaluations and determining the reserves classifications as of December 31, 2013, in accordance with the SEC regulatory standards. Ryder Scott reviewed the specific application of such methods and procedures for selected oil and gas properties considered to be a valid representation of Occidental’s 2013 year-end total proved reserves portfolio. In 2013, Ryder Scott reviewed approximately 21 percent of Occidental’s proved oil and gas reserves. Since being engaged in 2003, Ryder Scott has reviewed the specific application of Occidental’s reserve estimation methods and procedures for approximately 71 percent of Occidental’s existing proved oil and gas reserves. Management retains Ryder Scott to provide objective third-party input on its methods and procedures and to gather industry information applicable to Occidental’s reserve estimation and reporting process. Ryder Scott has not been engaged to render an opinion as to the reasonableness of reserves quantities reported by Occidental. Occidental has filed Ryder Scott's independent report as an exhibit to this Form 10-K.
Based on its reviews, including the data, technical processes and interpretations presented by Occidental, Ryder Scott has concluded that the overall procedures and methodologies Occidental utilized in estimating the proved reserves volumes, documenting the changes in reserves from prior estimates, preparing the economic evaluations and determining the reserves classifications for the reviewed properties are appropriate for the purpose thereof and comply with current SEC regulations.
Industry Outlook
The petroleum industry is highly competitive and subject to significant volatility due to numerous current and anticipated market conditions. The WTI and Brent oil price indexes fluctuated throughout 2013, settling at $98.42 per barrel and $110.80 per barrel, respectively, as of December 31, 2013.
Oil prices will continue to be affected by (i) global supply and demand, which are generally a function of global economic conditions, inventory levels, production disruptions, technological advances, regional market conditions and the actions of OPEC, other significant producers and governments; (ii) transportation capacity and cost in producing areas; (iii) currency exchange rates; and (iv) the effect of changes in these variables on market perceptions.
NGL prices are related to the supply and demand for the components of products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products for which they are used as feedstock. In addition, infrastructure constraints magnify the pricing volatility from region to region.
Domestic natural gas prices and local differentials are strongly affected by local supply and demand fundamentals, as well as government regulations and availability of transportation capacity from producing areas.
These and other factors make it impossible to predict the future direction of oil, NGL and domestic gas prices reliably. International gas prices are generally fixed under long-term contracts. Occidental continues to respond to economic conditions by adjusting capital expenditures in line with current economic conditions with the goal of keeping returns well above its cost of capital.
CHEMICAL SEGMENT
Business Environment
The modest pace of United States economic growth resulted in higher demand for domestically produced energy and feedstocks, resulting in higher raw material prices, though this did not have the same effect on all product prices. Chemical segment earnings, excluding the gain on sale of the Carbocloro investment, decreased in 2013, primarily due to higher energy and ethylene costs and lower chlor-alkali and chlorinated organics pricing driven by continued unfavorable supply and demand fundamentals.
Business Review
Basic Chemicals
During 2013, the modest pace of the United States economic growth much of the year resulted in lackluster domestic demand and pricing for basic chemical products. Industry chlorine operating rates remained relatively flat with 2012 at approximately 84 percent, preventing chlorine price improvement, and prices ended approximately 4 percent below where they began. Exports of downstream chlorine derivatives into the vinyls chain remained competitive as a result of the North American feedstock cost advantages, which are driven mostly by natural gas prices. Liquid caustic soda prices fell over the last two
quarters of 2013 and were slightly below the prior year levels for the whole year. In the domestic market, anticipation of additional capacity coming online in early 2014 from the commissioning of three additional chlor-alkali plants, including OxyChem’s 182,500-ton-per-year membrane plant in Tennessee, created downward pressure on liquid caustic soda prices during the second half of 2013. Export demand and pricing for liquid caustic soda was negatively impacted in mid-2013 by operational issues at a large Latin American alumina producer. Businesses such as calcium chloride and potassium hydroxide improved compared to 2012 as domestic demand improved and margins remained stable throughout the year.
Vinyls
Year-over-year domestic demand grew by more than 4 percent on the strength of the housing and commercial construction markets. This was offset by a decrease in exports, resulting in no change in industry operating rates in 2013 compared to 2012. Industry margins increased in 2013 due to higher PVC selling prices, partially offset by higher ethylene costs. North American, ethane-based ethylene continues to be cost-competitive versus prices in Europe and Asia, giving North American vinyl products an advantage in global markets. Despite the year-over-year reduction in North American exports of PVC, export volumes represented nearly 35 percent of total PVC sales of North American producers.
Industry Outlook
Industry performance will depend on the health of the global economy, specifically in the housing, construction, automotive and durable goods markets. Margins also depend on market supply and demand balances and feedstock and energy prices.
Basic Chemicals
Occidental expects that if the United States housing, automotive and durable goods markets continue to improve, domestic demand for basic chemical products should be higher in 2014. However, with forecasted capacity additions significantly exceeding closures, industry operating rates are expected to decline in 2014, resulting in increased competitive activity. Overall, improved demand in the face of increased capacity is anticipated to provide similar margins in 2014 for chlorine and caustic soda compared to 2013 levels. The continued competitiveness of downstream chlorine derivatives in global markets is contingent on United States feedstock costs, primarily natural gas and ethylene, remaining favorable compared to other global markets.
Vinyls
North American demand and operating rates should improve in 2014 if growth in both housing starts and commercial construction continues. Occidental expects export demand to remain firm and margins to improve over 2013.
MIDSTREAM AND MARKETING SEGMENT
Business Environment
Midstream and marketing segment earnings are affected by the performance of its marketing and trading businesses and its processing, transportation and power generation assets. The marketing and trading businesses aggregate and market Occidental's and third-party volumes, trade commodities and engage in storage activities. Marketing and trading performance is affected primarily by commodity price changes and margins in oil and gas transportation and storage programs. Processing and transportation results are affected by the volumes that are processed and transported through the segment's plants and pipelines, as well as the margins obtained on related services.
The midstream and marketing segment earnings in 2013, excluding the gain from the sale of a portion of an investment in Plains Pipeline, were greater than 2012, reflecting higher earnings in the pipeline and power generation businesses and improved marketing and trading performance. These improvements were partially offset by lower income in the gas processing business due in part to plant turnarounds in the Permian Basin operations.
Business Review
Marketing and Trading
The marketing and trading group markets substantially all of Occidental’s oil, NGLs and gas production, trades around its assets, including transportation and storage capacity, and engages in commodities trading. Occidental’s third-party marketing and trading activities focus on purchasing oil, NGLs and gas for resale from parties whose oil and gas supply is located near its transportation and storage assets. These purchases allow Occidental to aggregate volumes to better utilize and optimize its assets. In addition, Occidental’s Phibro trading unit's strategy is to profit from market price changes. Marketing performance improved mainly as a result of capturing regional crude price differentials by utilizing new pipelines providing access to the Gulf Coast refineries.
Gas Processing Plants and CO2 Fields and Facilities
Occidental processes its and third-party domestic wet gas to extract NGLs and other gas byproducts, including CO2, and delivers dry gas to pipelines. Margins primarily result from the difference between inlet costs of wet gas and market prices for NGLs. Occidental’s 2013 earnings from these operations decreased compared to 2012, which reflected lower NGL prices and plant turnarounds in the Permian Basin operations.
Occidental, together with ADNOC, is constructing a gas plant and facilities as part of the Al Hosn gas project in Abu Dhabi. The gas plant and facilities are expected to be completed and become operational in late 2014.
Pipeline Transportation
Margin and cash flow from pipeline transportation operations mainly reflect volumes shipped. Dolphin Energy owns and operates a 230-mile-long, 48-inch-diameter natural gas pipeline (Dolphin Pipeline), which transports dry natural gas from Qatar to the UAE and Oman. The Dolphin Pipeline contributes significantly to Occidental's pipeline transportation results through Occidental's 24.5-percent interest in Dolphin Energy. The Dolphin Pipeline has capacity to transport up to 3.2 Bcf of natural gas per day and currently transports approximately 2.3 Bcf per day. Dolphin Pipeline is currently expanding gas compression facilities to achieve maximum pipeline capacity. Occidental believes substantial opportunities remain to provide gas transportation to additional customers in the region to reach the full capacity of the Dolphin Pipeline and generate additional midstream revenues and cash flows.
Occidental owns an oil common carrier pipeline and storage system with approximately 2,800 miles of pipelines from southeast New Mexico across the Permian Basin of southwest Texas to Cushing, Oklahoma. The system has a current throughput capacity of about 616,000 barrels per day, 5.8 million barrels of active storage capability and 95 truck unloading facilities at various points along the system, which allow for additional volumes to be delivered into the pipeline.
Following the fourth quarter 2013 sale of a portion of its investment, Occidental owns approximately 25 percent of Plains Pipeline, a publicly-traded oil and gas pipeline transportation, storage, terminalling and marketing entity operating in Canada and the western and southern United States. The Plains Pipeline investment contributed over 25 percent of the segment's earnings for 2013, excluding the gain from the sale.
Occidental and Magellan are proceeding with construction of the BridgeTex Pipeline, which is expected to begin service in mid-2014. The approximately 450-mile-long pipeline will be capable of transporting approximately 300,000 barrels per day of crude oil between the Permian region (Colorado City, Texas) and Gulf Coast refinery markets. The BridgeTex Pipeline project also includes construction of approximately 2.6 million barrels of oil storage in aggregate.
Occidental's 2013 pipeline transportation earnings improved due to higher volumes and pricing, and higher income from Plains Pipeline and the Dolphin Pipeline.
Power Generation Facilities
Earnings from power and steam generation facilities are derived from sales to affiliates and third parties and are generally not material.
Industry Outlook
The pipeline transportation and power generation businesses are expected to remain relatively stable. The gas processing plant operations could have volatile results depending mostly on NGL prices, which cannot be predicted. Generally, higher NGL prices result in higher profitability. Although the marketing and the trading businesses individually can be volatile, the operations together tend to offset each other, significantly reducing the overall volatility of the midstream and marketing segment. Based on its framework of controls and risk management systems, Occidental does not expect the volatility of these operations to be significant to the company as a whole.
SEGMENT RESULTS OF OPERATIONS
Segment earnings exclude income taxes, interest income, interest expense, environmental remediation expenses, unallocated corporate expenses and discontinued operations, but include gains and losses from dispositions of segment assets and income from the segments' equity investments. Seasonality is not a primary driver of changes in Occidental's consolidated quarterly earnings during the year.
The following table sets forth the sales and earnings of each operating segment and corporate items:
In millions,
except per share amounts
For the years ended December 31,
NET SALES (a)
Oil and Gas
$
19,132
$
18,906
$
18,419
Chemical
4,673
4,580
4,815
Midstream and Marketing
1,538
1,399
1,447
Eliminations (a)
(888
)
(713
)
(742
)
$
24,455
$
24,172
$
23,939
EARNINGS
Oil and Gas (b)
$
7,894
$
7,095
$
10,241
Chemical (c)
Midstream and Marketing (d)
1,573
10,210
8,254
11,550
Unallocated corporate items
Interest expense, net (e)
(110
)
(117
)
(284
)
Income taxes
(3,755
)
(3,118
)
(4,201
)
Other (f)
(423
)
(384
)
(425
)
Income from continuing operations
5,922
4,635
6,640
Discontinued operations, net (g)
(19
)
(37
)
Net Income
$
5,903
$
4,598
$
6,771
Basic Earnings per Common Share
$
7.33
$
5.67
$
8.32
(a)
Intersegment sales eliminate upon consolidation and are generally made at prices approximating those that the selling entity would be able to obtain in third-party transactions.
(b)
The 2013 amount includes $607 million of pre-tax charges related to the impairment of domestic non-producing acreage. The 2012 amount includes pre-tax charges of $1.7 billion for the impairment of domestic gas assets and related items. The 2011 amount includes pre-tax charges of $35 million related to exploration write-offs in Libya and $29 million related to a Colombian net worth tax, and a pre-tax gain from the sale of an interest in a Colombian pipeline of $22 million.
(c)
The 2013 amount includes a $131 million pre-tax gain from the sale of an investment in Carbocloro, a Brazilian chemical facility.
(d)
The 2013 amount includes a $1,030 million pre-tax gain from the sale of a portion of an investment in Plains Pipeline and other items.
(e)
The 2011 amount includes a pre-tax charge of $163 million related to the premium on debt extinguishment.
(f)
The 2013 amount includes a $55 million pre-tax charge for the estimated cost related to the employment and post-employment benefits for the Company's former Executive Chairman and termination of certain other employees and consulting arrangements.
(g)
The 2011 amount includes a $144 million after-tax gain from the sale of the Argentine operations.
Oil and Gas
Dollars in millions, except as indicated
Segment Sales
$
19,132
$
18,906
$
18,419
Segment Earnings (a)
$
7,894
$
7,095
$
10,241
(a)
The 2013 amount includes pre-tax charges of $607 million for the impairment of domestic non-producing acreage. The 2012 amount includes pre-tax charges of $1.7 billion for the impairment of domestic gas assets and related items.
The following tables set forth the production and sales volumes of oil, NGLs and natural gas per day for each of the three years in the period ended December 31, 2013. The differences between the production and sales volumes per day are generally due to the timing of shipments at Occidental’s international locations where product is loaded onto tankers.
Production per Day
United States
Oil (MBBL)
California
Permian Basin
Midcontinent and Other
Total
NGLs (MBBL)
California
Permian Basin
Midcontinent and Other
Total
Natural gas (MMCF)
California
Permian Basin
Midcontinent and Other
Total
Latin America (a)
Oil (MBBL) - Colombia
Natural gas (MMCF) - Bolivia
Middle East/North Africa
Oil (MBBL)
Dolphin
Oman
Qatar
Other
Total
NGLs (MBBL)
Dolphin
Other
-
-
Total
Natural gas (MMCF)
Dolphin
Oman
Other
Total
Total Production (MBOE) (a,b)
(See footnotes following the Average Realized Prices table)
Sales Volumes per Day
United States
Oil (MBBL)
NGLs (MBBL)
Natural gas (MMCF)
Latin America (a)
Oil (MBBL) - Colombia
Natural gas (MMCF) - Bolivia
Middle East/North Africa
Oil (MBBL)
Dolphin
Oman
Qatar
Other
Total
NGLs (MBBL)
Dolphin
Other
-
-
Total
Natural gas (MMCF)
Total Sales Volumes (MBOE) (a,b)
(See footnotes following the Average Realized Prices table)
Average Realized Prices
Oil Prices ($ per bbl)
United States
$
96.42
$
93.72
$
92.80
Latin America (a)
$
103.21
$
98.35
$
97.16
Middle East/North Africa
$
104.48
$
108.76
$
104.34
Total worldwide (a)
$
99.84
$
99.87
$
97.92
NGL Prices ($ per bbl)
United States
$
41.80
$
46.07
$
59.10
Middle East/North Africa
$
33.00
$
37.74
$
32.09
Total worldwide
$
41.03
$
45.18
$
55.53
Gas Prices ($ per Mcf)
United States
$
3.37
$
2.62
$
4.06
Latin America (a)
$
11.17
$
11.85
$
10.11
Total worldwide (a)
$
2.54
$
2.06
$
3.01
(a)
For all periods presented, excludes volumes and amounts from the Argentine operations sold in 2011 and classified as discontinued operations.
(b)
Natural gas volumes have been converted to BOE based on energy content of six Mcf of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
Oil and gas segment earnings in 2013 included pre-tax charges of $0.6 billion for the impairment of domestic non-producing acreage while earnings in 2012 included pre-tax charges of $1.7 billion for the impairment of domestic gas assets and related items. In 2011, oil and gas segment earnings included pre-tax charges of $35 million related to exploration write-offs in Libya and $29 million related to Colombia net worth tax, as well as a pre-tax gain of $22 million from the sale of an interest in a Colombian pipeline.
Oil and gas segment earnings, prior to the impairment charges in both years, were $8.5 billion in 2013 compared to $8.8 billion in 2012. The year-over-year change in earnings resulted from higher domestic earnings, which were more than offset by lower international earnings. Higher domestic earnings resulted from improved oil and gas realized prices, higher liquids volumes and lower operating costs, partially offset by higher DD&A rates, stock price driven increases in equity compensation and lower NGL prices. Lower international earnings were caused by lower liquids sales volumes, lower oil prices and higher operating costs and DD&A rates in the Middle East/North Africa.
Average production costs for 2013, excluding taxes other than on income, were $13.76 per BOE, compared to $14.99 per BOE for 2012. This decrease reflected the impact of the domestic operational efficiency initiative where production costs decreased by $3.00 per BOE from $17.43 per BOE in 2012 to $14.43 per BOE in 2013. The domestic decrease was partially offset by higher international production costs due to higher volumes from Iraq, which has high operating costs.
Average daily oil and gas production volumes were 763,000 BOE for 2013, compared to 766,000 BOE for 2012. Occidental's daily domestic oil and NGL production increased by 11,000 BOE and 4,000 BOE, respectively, while gas production decreased by 33 MMcf. These results reflect Occidental's focus on oil drilling while reducing its drilling capital for gas in light of higher oil prices and lower gas prices in recent years. While domestic overall production improved by 9,000 BOE per day in 2013, international production was 12,000 BOE per day lower, mainly due to lower cost recovery barrels in the Dolphin and Oman operations and field and port strikes in Libya. Average daily sales volumes were 762,000 BOE in the 12 months of 2013, compared to 764,000 BOE for the same period in 2012.
Oil and gas segment earnings, prior to the charges and other items noted above, were $8.8 billion in 2012 compared to $10.3 billion in 2011. The decrease reflected lower NGL and gas prices, and higher DD&A rates, maintenance activity, field support costs and exploration expense, partially offset by higher oil prices and domestic volumes.
Average daily oil and gas production volumes were 766,000 BOE for 2012, compared to 733,000 BOE for 2011. Occidental's domestic production increased by 9 percent, while total company production increased by 5 percent. Dolphin's full cost recovery of pre-startup capital, which reduced production, was the only operation where PSCs and similar contracts had an appreciable effect on 2012
production volumes. Average daily sales volumes were 764,000 BOE in the twelve months of 2012, compared to 731,000 BOE for the same period in 2011.
Chemical
In millions
Segment Sales
$
4,673
$
4,580
$
4,815
Segment Earnings
$
$
$
Chemical segment earnings were $612 million in 2013, excluding the $131 million gain on sale of the Carbocloro investment, compared to $720 million in 2012. The year-over-year change in chemical segment earnings reflected higher energy and ethylene costs and lower chlor-alkali and chlorinated organics pricing driven by continued unfavorable supply and demand fundamentals and reduced export demand.
Chemical segment earnings were $720 million in 2012, compared to $861 million in 2011. The reduction was primarily the result of lower margins due to weaker economic conditions in Europe and Asia and increased competitive activity from these regions. The calcium chloride and potassium hydroxide businesses were also negatively impacted in 2012 by a mild winter and drought conditions in the United States.
Midstream, Marketing and Other
In millions
Segment Sales
$
1,538
$
1,399
$
1,447
Segment Earnings
$
1,573
$
$
Midstream and marketing segment earnings in 2013 were $543 million, excluding the $1.0 billion pre-tax gain from the sale of a portion of an investment in Plains Pipeline and other items, compared to $439 million in 2012. The 2013 results reflected higher earnings in the pipeline and power generation businesses and improved marketing and trading performance. Marketing performance improved by $110 million, mainly as a result of capturing regional crude price differentials by utilizing new pipelines providing access to the Gulf Coast refineries. These improvements were partially offset by lower income in the gas processing business due in part to the plant turnarounds in the Permian Basin operations.
Midstream and marketing segment earnings in 2012 were $439 million, compared to $448 million in 2011. The 2012 results reflected lower gas processing earnings, partially offset by improved marketing and trading performance.
SIGNIFICANT ITEMS AFFECTING EARNINGS
The following table sets forth, for the years ended December 31, 2013, 2012 and 2011, significant transactions and events affecting Occidental’s earnings that vary widely and unpredictably in nature, timing and amount:
Significant Items Affecting Earnings
Benefit (Charge) (in millions)
OIL AND GAS
Asset impairments and related items
$
(607
)
$
(1,731
)
$
-
Libya exploration write-off
-
-
(35
)
Gains on sale of Colombian pipeline interest
-
-
Foreign tax
-
-
(29
)
Total Oil and Gas
$
(607
)
$
(1,731
)
$
(42
)
CHEMICAL
Carbocloro sale gain
$
$
-
$
-
Total Chemical
$
$
-
$
-
MIDSTREAM AND MARKETING
Plains Pipeline sale gain and other
$
1,030
$
-
$
-
Total Midstream and Marketing
$
1,030
$
-
$
-
CORPORATE
Charge for former employees and consultants
$
(55
)
$
-
$
-
Litigation reserves
-
(20
)
-
Premium on debt extinguishments
-
-
(163
)
State income tax charge
-
-
(33
)
Tax effect of pre-tax adjustments
(179
)
Discontinued operations, net of tax (a)
(19
)
(37
)
Total Corporate
$
(253
)
$
$
(15
)
(a)
The 2011 amount includes a $144 million after-tax gain from the sale of the Argentine operations.
TAXES
Deferred tax liabilities, net of deferred tax assets of $1.6 billion, were $7.0 billion at December 31, 2013. The current portion of the deferred tax assets of $150 million is included in other current assets. The deferred tax assets, net of allowances, are expected to be realized through future operating income and reversal of temporary differences.
Worldwide Effective Tax Rate
The following table sets forth the calculation of the worldwide effective tax rate for income from continuing operations:
$ in millions
EARNINGS
Oil and Gas
$
7,894
$
7,095
$
10,241
Chemical
Midstream and Marketing
1,573
Unallocated Corporate Items
(533
)
(501
)
(709
)
Pre-tax income
9,677
7,753
10,841
Income tax expense
Federal and State
1,602
1,795
Foreign
2,153
2,424
2,406
Total income tax expense
3,755
3,118
4,201
Income from continuing operations
$
5,922
$
4,635
$
6,640
Worldwide effective tax rate
%
%
%
Occidental’s 2013 worldwide tax rate was 39 percent, slightly lower than 2012 due to proportionately higher domestic pre-tax income in 2013. The 2012 worldwide tax rate was higher than 2011 due to proportionately higher foreign pre-tax income in 2012.
A deferred tax liability has not been recognized for temporary differences related to unremitted earnings of certain consolidated foreign subsidiaries, as it is Occidental’s intention, generally, to reinvest such earnings permanently. If the earnings of these foreign subsidiaries were not indefinitely reinvested, an additional deferred tax liability of approximately $134 million would be required, assuming utilization of available foreign tax credits.
CONSOLIDATED RESULTS OF OPERATIONS
Changes in components of Occidental's results of operations are discussed below:
Revenue and Other Income Items
In millions
Net sales
$
24,455
$
24,172
$
23,939
Interest, dividends and other income
$
$
$
Gain on sale of equity investments
$
1,175
$
-
$
-
The increase in net sales in 2013, compared to 2012, was mainly due to improved domestic oil and gas realized prices and higher liquids volumes, partially offset by lower international liquids volumes and oil prices.
The increase in net sales in 2012, compared to 2011, was due to higher oil volumes and prices, partially offset by lower gas and NGL prices and lower prices and volumes across most chemical products.
Price and volume changes in the oil and gas segment generally represent a substantially larger portion of the overall change in net sales than the chemical and midstream and marketing segments.
The 2013 gain on sale of equity investments relates to the pre-tax gains from the sales of a portion of the investment in Plains Pipeline and the Carbocloro investment.
Expense Items
In millions
Cost of sales
$
7,562
$
7,844
$
7,385
Selling, general and administrative and other operating expenses
$
1,801
$
1,602
$
1,523
Depreciation, depletion and amortization
$
5,347
$
4,511
$
3,591
Asset impairments and related items
$
$
1,751
$
-
Taxes other than on income
$
$
$
Exploration expense
$
$
$
Interest and debt expense, net
$
$
$
Cost of sales decreased in 2013, compared to 2012, due to lower oil and gas operating costs, partially offset by higher energy and feedstock costs in the chemical segment. The reduction in oil and gas operating costs
reflected a wide range of initiatives, including high-grading of service rigs, improved job scheduling and liquids usage and handling, optimizing field supervision and reduced consumption of fuel, power and field rental equipment.
Cost of sales increased in 2012, compared to 2011, due to higher oil and gas volumes and operating costs, mostly resulting from higher maintenance activity and field support costs, partially offset by lower feedstock and energy costs in the chemical segment.
Selling, general and administrative and other operating expenses increased in 2013 due to higher compensation and employee-related costs, in particular higher equity compensation due to higher stock prices and higher headcount in 2013 compared to 2012, as well as the charge related to the employment and post-employment benefits for Occidental's former Executive Chairman and termination of certain other employees and consulting arrangements.
Selling, general and administrative and other operating expenses increased in 2012 due to higher headcount, partially offset by lower equity compensation expense and the Colombia net worth tax, which increased the 2011 costs.
DD&A increased in each year from 2011 to 2013, generally due to higher DD&A rates and, to a lesser extent, the changes in volumes in the oil and gas segment.
Asset impairments and related items in 2013 of $621 million were mostly related to the impairment of certain non-producing domestic oil and gas acreage.
Asset impairments and related items in 2012 were almost all in Midcontinent, over 90 percent of which were related to natural gas properties that were acquired more than five years ago on average when gas prices were above $6 per Mcf.
Taxes other than on income increased in each year from 2011 to 2013, due to higher domestic oil volumes and oil and gas prices. During the period from 2011 to 2013, these expenses also reflected increasing domestic ad valorem taxes resulting from higher property values and California greenhouse gas costs.
Interest and debt expense, net, in 2011, included a $163 million early debt extinguishment charge.
Other Items
Income/(expense) (in millions)
Provision for income taxes
$
(3,755
)
$
(3,118
)
$
(4,201
)
Income from equity investments
$
$
$
Discontinued operations, net
$
(19
)
$
(37
)
$
Provision for income taxes increased in 2013, compared to 2012, due to higher pre-tax income, partially offset by a slightly lower effective tax rate. The lower tax rate was due to higher proportional domestic pre-tax income in 2013, compared to 2012.
Provision for income taxes decreased in 2012, compared to 2011, due to lower pre-tax income, partially offset by a slightly higher effective tax rate. The higher tax rate was due to higher proportional foreign pre-tax income in 2012, compared to 2011.
Discontinued operations, net, in 2011, included the $144 million after-tax gain recorded from the sale of the Argentine operations.
CONSOLIDATED ANALYSIS OF FINANCIAL POSITION
The changes in select components of Occidental’s balance sheet are discussed below:
Balance Sheet Components
In millions
CURRENT ASSETS
Cash and cash equivalents
$
3,393
$
1,592
Trade receivables, net
5,674
4,916
Inventories
1,200
1,344
Other current assets
1,056
1,640
Total current assets
$
11,323
$
9,492
Investments in unconsolidated entities
$
1,459
$
1,894
Property, plant and equipment, net
$
55,821
$
52,064
Long-term receivables and other assets, net
$
$
CURRENT LIABILITIES
Current maturities of long-term debt
$
-
$
Accounts payable
5,520
4,708
Accrued liabilities
2,556
1,966
Domestic and foreign income taxes
Total current liabilities
$
8,434
$
7,290
Long-term debt, net
$
6,939
$
7,023
Deferred credits and other liabilities-income taxes
$
7,197
$
6,039
Deferred credits and other liabilities-other
$
3,501
$
3,810
Stockholders’ equity
$
43,372
$
40,048
Assets
See "Liquidity and Capital Resources - Cash Flow Analysis" for discussion of the change in cash and cash equivalents.
The increase in trade receivables, net, was due to higher oil and gas prices and higher equity and third-party oil volumes at the end of 2013, compared to the end of 2012. The decrease in inventories primarily resulted from lower storage inventories. The decrease in other current assets mainly reflected the collection of a tax refund in 2013. The decrease in investments in unconsolidated entities was due to the sales of a portion of Occidental's interest in Plains Pipeline and the investment in Carbocloro. The increase in PP&E, net, was due to capital expenditures and acquisitions of oil and gas properties, partially offset by DD&A and asset impairments.
Liabilities and Stockholders' Equity
The decrease in current maturities of long-term debt was due to the redemption of the $600 million senior notes that matured in 2013. The increase in accounts payable reflected higher oil and gas prices, higher equity and third-party oil volumes and higher capital expenditures at the end of 2013, compared to the end of 2012. The December 31, 2013 accrued liability balance included the accrual of the fourth quarter 2013 dividend to be paid in 2014, while the 2012 balance did not include a dividend accrual due to
the accelerated payment of the fourth quarter dividend during that year. The increase in domestic and foreign income taxes reflected the lack of a 2012 accrual resulting from a refund due at the end of that year. The increase in deferred and other domestic and foreign income taxes was mainly due to faster tax depreciation on capital expenditures. The decrease in deferred credits and other liabilities was primarily due to the reduction of pension and postretirement plan liabilities. The increase in stockholders' equity reflected net income for 2013 and reduced pension and postretirement obligations, partially offset by dividends and treasury stock purchases.
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 2013, Occidental had approximately $3.4 billion in cash and cash equivalents. While a substantial majority of this cash is held and available for use in the United States, Occidental believes the cash in foreign jurisdictions can be brought to the United States without paying significant taxes. Income and cash flows are largely dependent on the oil and gas segment's prices, sales volumes and costs. Occidental believes that cash on hand and cash generated from operations will be sufficient to fund its operating needs and planned capital expenditures, dividends and any debt payments.
Occidental has a bank credit facility (Credit Facility) with a $2.0 billion commitment expiring in 2016. No amounts have been drawn under this Credit Facility. Up to $1.0 billion of the Credit Facility is available in the form of letters of credit. Borrowings under the Credit Facility bear interest at various benchmark rates, including LIBOR, plus a margin based on Occidental's senior debt ratings. Additionally, Occidental paid average annual facility fees of 0.08 percent in 2013 on the total commitment amounts of the Credit Facility.
The Credit Facility provides for the termination of loan commitments and requires immediate repayment of any outstanding amounts if certain events of default occur. The Credit Facility and other debt agreements do not contain material adverse change clauses or debt ratings triggers that could restrict Occidental's ability to borrow or that would permit lenders to terminate their commitments or accelerate debt.
As of December 31, 2013, under the most restrictive covenants of its financing agreements, Occidental had substantial capacity for additional unsecured borrowings, the payment of cash dividends and other distributions on, or acquisitions of, Occidental stock. Occidental also has a shelf registration statement that facilitates future issuances of securities.
Occidental, from time to time, may access and has accessed debt markets for general corporate purposes, including acquisitions. At this time, Occidental does not anticipate any need for such funding.
Cash Flow Analysis
In millions
Net cash provided by operating activities
$
12,927
$
11,312
$
12,281
Net income increased by $1.3 billion in 2013 compared to 2012, while cash provided by operating activities increased by $1.6 billion. These differences reflect working capital changes and collection of a tax refund increased cash flow from operations by $1.8 billion in 2013, compared to 2012, offset by the $1.2 billion gains on sales of equity investments in 2013 and $0.3 billion of lower non-cash charges. The most significant changes in non-cash charges from 2012 to 2013 were lower asset impairments by $1.1 billion, partially offset by higher DD&A expenses by $0.8 billion. The 2013 net income included gains on the sales of equity investments for which cash is reported as an investing activity.
The increase in operating cash flows in 2013, compared to 2012, also reflected lower domestic oil and gas operating costs, 3-percent and 29-percent higher domestic prices for oil and gas, respectively, and higher domestic oil volumes, partially offset by the Middle East/North Africa's lower oil volumes and prices and higher operating costs.
Other cost elements, such as labor costs and overhead, are not significant drivers of changes in cash flow because they are relatively stable within a narrow range over the short to intermediate term. Changes in these costs had a much smaller effect on cash flow than the changes in oil and gas product prices and volumes and operating costs.
Although net income decreased by $2.2 billion for the 12 months ended December 31, 2012, compared to the same period of 2011, net cash provided by operating activities only decreased by $1.0 billion for this period. Compared to 2011, net income in 2012 included much larger non-cash charges, which reduced net income but not cash provided by operating activities. These non-cash charges mainly comprised asset impairments and higher DD&A. Working capital changes in 2012 further reduced cash flow from operations by approximately $0.8 billion, compared to 2011.
Additionally, operating cash flows in 2012, compared to 2011, reflected lower domestic gas and worldwide NGL prices, by 35 percent and 19 percent, respectively, and higher maintenance activity and field support costs, partially offset by higher domestic oil volumes and 2-percent higher worldwide oil prices. The positive cash-flow impact of the oil price change was more than offset by the negative effect of significant declines in gas and NGL prices. The decrease in operating cash flows in 2012, compared to 2011, also reflected lower chemical margins, primarily due to weaker economic conditions in Europe and Asia.
The impact of the chemical and the midstream and marketing segments on overall cash flows is generally less significant than the impact of the oil and gas segment because the chemical and midstream and marketing segments are significantly smaller.
Other non-cash charges to income in 2013, 2012 and 2011 included charges for stock-based compensation plans and asset retirement obligation accruals.
Operating cash flows for discontinued operations include the Argentine operations through the date they were sold in 2011.
Cash used by investing activities
(in millions)
Capital expenditures
Oil and Gas
$
(7,045
)
$
(8,220
)
$
(6,145
)
Chemical
(424
)
(357
)
(234
)
Midstream and Marketing
(1,404
)
(1,558
)
(1,089
)
Corporate
(164
)
(91
)
(50
)
Total
(9,037
)
(10,226
)
(7,518
)
Other investing activities, net
(2,429
)
(4,955
)
Net cash used by investing activities - continuing operations
(8,193
)
(12,655
)
(12,473
)
Investing cash flow from discontinued operations
-
-
2,570
Net cash used by investing activities
$
(8,193
)
$
(12,655
)
$
(9,903
)
Compared to $10.2 billion in 2012, Occidental's net capital expenditures for 2013 were $8.8 billion after $0.2 billion in BridgeTex partner contributions, which are included in financing activities. The decrease in capital expenditures of $1.4 billion from 2012 to 2013 was mainly due to the $1.2 billion decrease in oil and gas expenditures, a majority of which was in domestic properties. This reduction reflected cost savings from Occidental's efficiency initiatives. The increase for the chemical segment was due to the continued construction of the Tennessee chlor-alkali facility. The decrease in the midstream and marketing capital expenditures was due to lower spending for the Al Hosn gas project, partially offset by increased spending for BridgeTex.
Occidental’s net capital spending is expected to increase in 2014 to approximately $10.2 billion, compared to $8.8 billion in 2013. Approximately $1.2 billion of the increase will be in the oil and gas segment and includes additional capital allocated to the California and Permian Basin operations of approximately $0.4 billion each. Those operations will use the capital almost entirely for additional oil drilling to accelerate their development plans and production growth. An additional $0.1 billion is expected to be spent on these and other domestic assets for facilities projects that were deferred in 2013. Occidental also expects to continue to fund growth opportunities in key international assets, mainly Oman and Qatar, which will get approximately $0.3 billion of the increased capital, and complete the Al Hosn gas project, where the capital expenditures are expected to be lower in 2014 compared to 2013. Exploration capital is expected to increase by approximately $0.1 billion, in part due to deferred spending in 2013. The total midstream and marketing capital will increase by approximately $0.1 billion for the BridgeTex Pipeline and the chemical capital will increase slightly due to the ethylene cracker project announced in 2013. The 2014 capital program is expected to be approximately 80 percent in oil and gas, 7 percent in the Al Hosn gas project,
7 percent in domestic midstream and marketing and the remainder in the chemical segment.
The 2013 other investing activities, net amount included $1.6 billion of cash received from the sales of a portion of Occidental's interest in Plains Pipeline and the investment in Carbocloro, partially offset by $0.6 billion in cash payments for the acquisitions of businesses and assets, largely consisting of various interests in domestic oil and gas properties.
The increase in capital expenditures of $2.7 billion from 2011 to 2012 was mainly due to the $2.1 billion increase in oil and gas expenditures, a majority of which was in domestic properties, such as Permian and California, as well as increases throughout the Middle East. The increase in the midstream and marketing capital expenditures was almost entirely due to the Al Hosn gas project.
The 2012 other investing activities, net amount included $2.5 billion in cash payments for the acquisitions of businesses and assets, largely consisting of various interests in domestic oil and gas properties in the Permian Basin, the Williston Basin, California and South Texas. Also included in 2012 investing activities was approximately $190 million of cash dividends received as investment returns.
The 2011 other investing activities, net amount included $4.9 billion in cash payments for the acquisitions of businesses and assets, including various interests in domestic oil and gas properties, in operated, producing and non-producing properties in California and the Permian and Williston basins for approximately $2.4 billion, properties in South Texas for $1.8 billion and $0.5 billion for Occidental’s share of pre-acquisition development expenditures incurred by the Al Hosn gas project.
Investing cash flow from discontinued operations included $2.6 billion of cash received from the sale of the Argentine operations in 2011.
Commitments at December 31, 2013, for major fixed and determinable capital expenditures were approximately $2.1 billion, which will be due in 2014 and beyond. Occidental expects to fund its commitments and capital expenditures with cash from operations.
In millions
Net cash used by financing activities
$
(2,933
)
$
(846
)
$
(1,175
)
The 2013 net cash used by financing activities included $0.7 billion used to retire debt and $0.2 billion of contributions received from a noncontrolling interest. Common stock dividends paid decreased by $0.6 billion to $1.6 billion in 2013, due to the accelerated payment in 2012 of that year's fourth quarter dividend. In addition, purchases of treasury stock increased from $0.6 billion in 2012 to over $0.9 billion in 2013. Higher 2013 net cash use compared to 2012 also reflected the net proceeds in 2012 of approximately $1.7 billion from the issuance of senior unsecured notes that year.
In 2012 common stock dividends paid increased by $0.7 billion to $2.1 billion compared to 2011, which included the accelerated payment of the fourth quarter dividend. In addition, purchases of treasury stock increased from $0.3 billion in 2011 to $0.6 billion in 2012. The 2012 cash flows also reflected $1.7 billion of proceeds from the issuance of unsecured notes.
The 2011 amount included net proceeds of approximately $2.1 billion from the issuance of senior unsecured notes and cash use of $1.5 billion to retire long-term debt.
OFF-BALANCE-SHEET ARRANGEMENTS
The following is a description of the business purpose and nature of Occidental's off-balance-sheet arrangements.
Guarantees
Occidental has guaranteed certain equity investees' debt and has entered into various other guarantees including performance bonds, letters of credit, indemnities and commitments provided by Occidental to third parties, mainly to provide assurance that OPC or its subsidiaries and affiliates will meet their various obligations (guarantees). As of December 31, 2013, Occidental’s guarantees were not material and a substantial majority consisted of limited recourse guarantees on approximately $354 million of Dolphin’s debt. The fair value of the guarantees was immaterial.
See "Oil and Gas Segment - Business Review - Qatar" and “Segment Results of Operations” for further information about Dolphin.
Leases
Occidental has entered into various operating lease agreements, mainly for transportation equipment, power plants, machinery, terminals, storage facilities, land and office space. Occidental leases assets when leasing offers greater operating flexibility. Lease payments are generally expensed as part of cost of sales and selling, general and administrative expenses. For more information, see "Contractual Obligations."
CONTRACTUAL OBLIGATIONS
The table below summarizes and cross-references Occidental’s contractual obligations. This summary indicates on- and off-balance-sheet obligations as of December 31, 2013.
Contractual Obligations
(in millions)
Payments Due by Year
Total
and
and
and
thereafter
On-Balance Sheet
Long-term debt (Note 5) (a)
$
6,964
$
-
$
1,450
$
1,750
$
3,764
Other long-term liabilities (b)
1,874
Off-Balance Sheet
Operating leases (Note 6)
1,166
Purchase obligations (c)
10,024
2,977
2,656
1,371
3,020
Total
$
20,028
$
3,360
$
4,722
$
3,602
$
8,344
(a)
Excludes unamortized debt discount and interest on the debt. As of December 31, 2013, interest on long-term debt totaling $1.4 billion is payable in the following years (in millions): 2014 - $218, 2015 and 2016 - $402, 2017 and 2018 - $292, 2019 and thereafter - $505.
(b)
Includes obligations under postretirement benefit and deferred compensation plans, as well as certain accrued liabilities.
(c)
Amounts include payments which will become due under long-term agreements to purchase goods and services used in the normal course of business to secure terminal and pipeline capacity, drilling rigs and services, CO2, electrical power, steam and certain chemical raw materials. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Long-term purchase contracts are discounted at a 3.1-percent discount rate.
Delivery Commitments
Occidental has made commitments to certain refineries and other buyers to deliver oil, gas and NGLs. The total amount contracted to be delivered, a substantial majority of which is in the United States, is approximately 73 million barrels of oil through 2019, 83 billion cubic feet of gas through 2016 and 15 million barrels of NGLs through 2015. The price for these deliveries is set at the time of delivery of the product. Occidental has significantly more production capacity than the amounts committed and has the ability to secure additional volumes in case of a shortfall. None of the commitments in any given year is expected to have a material impact on Occidental's financial statements.
LAWSUITS, CLAIMS AND CONTINGENCIES
OPC or certain of its subsidiaries are involved, in the normal course of business, in lawsuits, claims and other legal proceedings 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. OPC or certain of its subsidiaries also are involved in proceedings under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) and
similar federal, state, local and foreign environmental laws. These environmental proceedings seek funding or performance of remediation and, in some cases, compensation for alleged property damage, punitive damages, civil penalties and injunctive relief. Usually OPC or such subsidiaries are among many companies in these environmental proceedings and have to date been successful in sharing response costs with other financially sound companies. Further, some lawsuits, claims and legal proceedings involve acquired or disposed assets with respect to which a third party or Occidental retains liability or indemnifies the other party for conditions that existed prior to the transaction.
Occidental accrues 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. Occidental has disclosed its reserve balances for environmental matters. Reserve balances for other matters as of December 31, 2013 and 2012, were not material to Occidental's consolidated balance sheets. Occidental also evaluates the amount of reasonably possible losses that it could incur as a result of the matters mentioned above. Occidental has disclosed its range of reasonably possible additional losses for sites where it is a participant in environmental remediation. Occidental believes that other reasonably possible losses that it could incur in excess of reserves accrued on the balance sheet would not be material to its consolidated financial position or results of operations. Environmental matters are further discussed under the caption "Environmental Liabilities and Expenditures" below.
During the course of its operations, Occidental is subject to audit by tax authorities for varying periods in various federal, state, local and foreign tax jurisdictions. Although taxable years through 2009 for United States federal income tax purposes have been audited by the United States Internal Revenue Service (IRS) pursuant to its Compliance Assurance Program, subsequent taxable years are currently under review. Additionally, in December 2012, Occidental filed United States federal refund claims for tax years 2008 and 2009 which are subject to IRS review. Taxable years from 2000 through the current year remain subject to examination by foreign and state government tax authorities in certain jurisdictions. In certain of these jurisdictions, tax authorities are in various stages of auditing Occidental's income taxes. During the course of tax audits, disputes have arisen and other disputes may arise as to facts and matters of law. Occidental believes that the resolution of outstanding tax matters would not have a material adverse effect on its consolidated financial position or results of operations.
OPC, its subsidiaries, or both, have indemnified various parties against specified liabilities those parties might incur in the future in connection with purchases and other transactions that they have entered into with Occidental. These indemnities usually are contingent upon the other party incurring liabilities that reach specified thresholds. As of December 31, 2013, Occidental is not aware of circumstances that it believes would reasonably be expected to lead to indemnity claims that would result in payments materially in excess of reserves.
ENVIRONMENTAL LIABILITIES AND EXPENDITURES
Occidental’s operations are subject to stringent federal, state, local and foreign laws and regulations related to improving or maintaining environmental quality. Occidental’s environmental compliance costs have generally increased over time and are expected to rise in the future. Occidental factors environmental expenditures for its operations into its business planning process as an integral part of producing quality products responsive to market demand.
Environmental Remediation
The laws that require or address environmental remediation, including CERCLA and similar federal, state, local and foreign laws, may apply retroactively and regardless of fault, the legality of the original activities or the current ownership or control of sites. OPC or certain of its subsidiaries participate in or actively monitor a range of remedial activities and government or private proceedings under these laws with respect to alleged past practices at operating, closed and third-party sites. Remedial activities may include one or more of the following: investigation involving sampling, modeling, risk assessment or monitoring; cleanup measures including removal, treatment or disposal; or operation and maintenance of remedial systems. The environmental proceedings seek funding or performance of remediation and, in some cases, compensation for alleged property damage, punitive damages, civil penalties, injunctive relief and government oversight costs.
As of December 31, 2013, Occidental participated in or monitored remedial activities or proceedings at 157 sites. The following table presents Occidental’s environmental remediation reserves as of December 31, 2013, 2012 and 2011, grouped as environmental remediation sites listed or proposed for listing by the U.S. Environmental Protection Agency on the CERCLA National Priorities List (NPL sites) and three categories of non-NPL sites - third-party sites, Occidental-operated sites and closed or non-operated Occidental sites.
$ amounts
in millions
# of
Sites
Reserve
Balance
# of
Sites
Reserve
Balance
# of
Sites
Reserve
Balance
NPL sites
$
$
$
Third-party sites
Occidental-operated sites
Closed or non-operated Occidental sites
Total
$
$
$
As of December 31, 2013, Occidental’s environmental reserves exceeded $10 million each at 10 of the 157 sites described above, and 108 of the sites had reserves from $0 to $1 million each.
As of December 31, 2013, two sites - a landfill in western New York owned by Occidental and a former facility in New York - accounted for 60 percent of its reserves associated with NPL sites. In connection with a 1986 acquisition, Maxus Energy Corporation has retained the liability and is indemnifying Occidental for 14 of the remaining NPL sites.
As of December 31, 2013, Maxus has also retained the liability and is indemnifying Occidental for 8 of the 74 third-party sites. Three of the remaining 66 third-party sites - a former copper mining and smelting operation in Tennessee, a containment and removal project in Tennessee and an active refinery in Louisiana where Occidental reimburses the current owner for certain remediation activities - accounted for 52 percent of Occidental’s reserves associated with these sites.
Four sites - chemical plants in Kansas, Louisiana and New York and a group of oil and gas properties in the southwestern United States - accounted for 61 percent of the reserves associated with the Occidental-operated sites.
Four other sites - a landfill in western New York, former chemical plants in Tennessee and Delaware and a closed coal mine in Pennsylvania - accounted for 64 percent of the reserves associated with closed or non-operated Occidental sites.
Environmental reserves vary over time depending on factors such as acquisitions or dispositions, identification of additional sites and remedy selection and implementation. The following table presents environmental reserve activity for the past three years:
In millions
Balance - Beginning of Year
$
$
$
Remediation expenses and interest accretion
Changes from acquisitions/dispositions
-
-
Payments
(74
)
(72
)
(73
)
Balance - End of Year
$
$
$
Based on current estimates, Occidental expects to expend funds corresponding to approximately half of the current environmental reserves at the sites described above over the next three to four years and the balance at these sites over the subsequent 10 or more years. Occidental believes its range of reasonably possible additional losses beyond those liabilities recorded for environmental remediation at these sites could be up to $380 million. See "Critical Accounting Policies and Estimates - Environmental Liabilities and Expenditures" for additional information.
Environmental Costs
Occidental’s environmental costs, some of which include estimates, are presented below for each segment for each of the years ended December 31:
In millions
Operating Expenses
Oil and Gas
$
$
$
Chemical
Midstream and Marketing
$
$
$
Capital Expenditures
Oil and Gas
$
$
$
Chemical
Midstream and Marketing
$
$
$
Remediation Expenses
Corporate
$
$
$
Operating expenses are incurred on a continual basis. Capital expenditures relate to longer-lived improvements in properties currently operated by Occidental. Remediation expenses relate to existing conditions from past operations.
Occidental presently estimates capital expenditures for environmental compliance of approximately $130 million for 2014.
FOREIGN INVESTMENTS
Many of Occidental’s assets are located outside North America. At December 31, 2013, the carrying value of Occidental’s assets in countries outside North America aggregated approximately $13.7 billion, or approximately 20 percent of Occidental’s total assets at that date. Of such assets, approximately $11.9 billion are located in the Middle East/North Africa and approximately $1.7 billion are located in Latin America. For the year ended December 31, 2013, net sales outside North America totaled $8.2 billion, or approximately 34 percent of total net sales.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The process of preparing financial statements in accordance with generally accepted accounting principles requires Occidental's management to make informed estimates and judgments regarding certain items and transactions. Changes in facts and circumstances or discovery of new information may result in revised estimates and judgments, and actual results may differ from these estimates upon settlement but generally not by material amounts. There has been no material change to Occidental's critical accounting policies over the past three years. The selection and development of these policies and estimates have been discussed with the Audit Committee of the Board of Directors. Occidental considers the following to be its most critical accounting policies and estimates that involve management's judgment.
Oil and Gas Properties
The carrying value of Occidental’s PP&E represents the cost incurred to acquire or develop the asset, including any asset retirement obligations and capitalized interest, net of accumulated depreciation, depletion and amortization and any impairment charges. For assets acquired, PP&E cost is based on fair values at the acquisition date. Asset retirement obligations and interest costs incurred in connection with qualifying capital expenditures are capitalized and amortized over the lives of the related assets.
Occidental uses the successful efforts method to account for its oil and gas properties. Under this method, Occidental capitalizes costs of acquiring properties, costs of drilling successful exploration wells and development costs. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. If proved reserves have been found, the costs of exploratory wells remain capitalized. Otherwise, Occidental charges the costs of the related wells to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Occidental generally expenses the costs of such exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete.
Occidental expenses annual lease rentals, the costs of injectants used in production and geological, geophysical and seismic costs as incurred.
Occidental determines depreciation and depletion of oil and gas producing properties by the unit-of-production method. It amortizes acquisition costs over total proved reserves and capitalized development and successful exploration costs over proved developed reserves.
Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Occidental has no proved oil and gas reserves for which the determination of economic producibility is subject to the completion of major additional capital expenditures.
Several factors could change Occidental’s proved oil and gas reserves. For example, Occidental receives a share of production from PSCs to recover its costs and generally an additional share for profit. Occidental’s share of production and reserves from these contracts decreases when product prices rise and increases when prices decline. Overall, Occidental’s net economic benefit from these contracts is greater at higher product prices. In other cases, particularly with long-lived properties, lower product prices may lead to a situation where production of a portion of proved reserves becomes uneconomical. For such properties, higher product prices typically result in additional reserves becoming economical. Estimation of
future production and development costs is also subject to change partially due to factors beyond Occidental's control, such as energy costs and inflation or deflation of oil field service costs. These factors, in turn, could lead to changes in the quantity of proved reserves. Additional factors that could result in a change of proved reserves include production decline rates and operating performance differing from those estimated when the proved reserves were initially recorded. In 2013, revisions of previous estimates provided a net 4 million BOE increase in proved reserves, which amounted to less than 1 percent of Occidental's total reserves as of December 31, 2013.
Additionally, Occidental performs impairment tests with respect to its proved properties when product prices decline other than temporarily, reserve estimates change significantly, other significant events occur or management's plans change with respect to these properties in a manner that may impact Occidental's ability to realize the recorded asset amounts. Impairment tests incorporate a number of assumptions involving expectations of undiscounted future cash flows, which can change significantly over time. These assumptions include estimates of future product prices, which Occidental bases on forward price curves and, when applicable, contractual prices, estimates of oil and gas reserves and estimates of future expected operating and development costs. Any impairment loss would be calculated as the excess of the asset's net book value over its estimated fair value.
The most significant ongoing financial statement effect from a change in Occidental's oil and gas reserves or impairment of its proved properties would be to the DD&A rate. For example, a 5-percent increase or decrease in the amount of oil and gas reserves would change the DD&A rate by approximately $0.85 per barrel, which would increase or decrease pre-tax income by approximately $240 million annually at current production rates. The change in the DD&A rate over the past three years due to revisions of previous proved reserve estimates has been immaterial.
A portion of the carrying value of Occidental’s oil and gas properties is attributable to unproved properties. At December 31, 2013, the net capitalized costs attributable to unproved properties were $3.6 billion. The unproved amounts are not subject to DD&A until they are classified as proved properties. As exploration and development work progresses, if reserves on these properties are proved, capitalized costs attributable to the properties become subject to DD&A. If the exploration and development work were to be unsuccessful, or management decided not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions or other factors, the capitalized costs of the related properties would be expensed. The timing of any writedowns of these unproved properties, if warranted, depends upon management's plans, the nature, timing and extent of future exploration and development activities and their results. Occidental believes its current plans and exploration and development efforts will allow it to realize its unproved property balance.
During its annual capital planning process in the fourth quarter of 2013, management determined that it would not pursue development of certain of its non-producing domestic oil and gas acreage based on product prices, availability of transportation capacity to market the products and regulatory and environmental considerations. As a result, Occidental recorded pre-tax impairment charges of $0.6 billion for the acreage.
The profitability of certain of Occidental's Middle East/North Africa operations, and in turn its ability to realize its recorded asset values, is dependent upon the success of future development plans or normalization of operations in some locations. Further, the strategic review Occidental is currently undertaking may result in the sale of certain assets, some of which may result in losses. Such losses, if any, will be recorded when a definitive sale decision is made.
Chemical Assets
Occidental's chemical assets are depreciated using either the unit-of-production or the straight-line method, based upon the estimated useful lives of the facilities. The estimated useful lives of Occidental’s chemical assets, which range from three years to 50 years, are also used for impairment tests. The estimated useful lives for the chemical facilities are based on the assumption that Occidental will provide an appropriate level of annual expenditures to ensure productive capacity is sustained. Such expenditures consist of ongoing routine repairs and maintenance, as well as planned major maintenance activities (PMMA). Ongoing routine repairs and maintenance expenditures are expensed as incurred. PMMA costs are capitalized and amortized over the period until the next planned overhaul. Additionally, Occidental incurs capital expenditures that extend the remaining useful lives of existing assets, increase their capacity or operating efficiency beyond the original specification or add value through modification for a different use. These capital expenditures are not considered in the initial determination of the useful lives of these assets at the time they are placed into service. The resulting revision, if any, of the asset’s estimated useful life is measured and accounted for prospectively.
Without these continued expenditures, the useful lives of these assets could decrease significantly. Other factors that could change the estimated useful lives of Occidental’s chemical assets include sustained higher or lower product prices, which are particularly affected by both domestic and foreign competition, demand, feedstock costs, energy prices, environmental regulations and technological changes.
Occidental performs impairment tests on its chemical assets whenever events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or when management’s plans change with respect to those assets. Any impairment loss would be calculated as the excess of the asset's net book value over its estimated fair value.
Occidental's net PP&E for the chemical segment is approximately $2.8 billion and its depreciation expense for 2014 is expected to be approximately $325 million. The most significant financial statement impact of a decrease in the estimated useful lives of Occidental's chemical plants would be on depreciation expense. For example, a reduction in the remaining useful lives of one year would increase depreciation and reduce pre-tax earnings by approximately $45 million per year.
Midstream, Marketing and Other Assets
Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty. Occidental applies hedge accounting when transactions meet specified criteria for cash-flow hedge treatment and management elects and documents such treatment. Otherwise, any fair value gains or losses are recognized in earnings in the current period. For cash-flow hedges, the gain or loss on the effective portion of the derivative is reported as a component of other comprehensive income (OCI) with an offsetting adjustment to the basis of the item being hedged. Realized gains or losses from cash-flow hedges, and any ineffective portion, are recorded as a component of net sales in the consolidated statements of income. Ineffectiveness is primarily created by a lack of correlation between the hedged item and the hedging instrument due to location, quality, grade or changes in the expected quantity of the hedged item. Gains and losses from derivative instruments are reported net in the consolidated statements of income. There were no fair value hedges as of and during the year ended December 31, 2013.
A hedge is regarded as highly effective such that it qualifies for hedge accounting if, at inception and throughout its life, it is expected that changes in the fair value or cash flows of the hedged item will be offset by 80 to 125 percent of the changes in the fair value or cash flows, respectively, of the hedging instrument. In the case of hedging a forecast transaction, the transaction must be probable and must present an exposure to variations in cash flows that could ultimately affect reported net income or loss. Occidental discontinues hedge accounting when it determines that a derivative has ceased to be highly effective as a hedge; when the hedged item matures or is sold or repaid; or when a forecast transaction is no longer deemed probable.
Occidental's midstream and marketing PP&E is depreciated over the estimated useful lives of the assets, using either the unit-of-production or straight-line method. Occidental performs impairment tests on its midstream and marketing assets whenever events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or when management’s plans change with respect to those assets. Any impairment loss would be calculated as the excess of the asset's net book value over its estimated fair value.
Fair Value Measurements
Occidental has categorized its assets and liabilities that are measured at fair value in a three-level fair value hierarchy, based on the inputs to the valuation techniques: Level 1 - using quoted prices in active markets for the assets or liabilities; Level 2 - using observable inputs other than quoted prices for the assets or liabilities; and Level 3 - using unobservable inputs. Transfers between levels, if any, are recognized at the end of each reporting period.
Fair Values - Recurring
Occidental primarily applies the market approach for recurring fair value measurements, maximizes its use of observable inputs and minimizes its use of unobservable inputs. Occidental utilizes the mid-point between bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, Occidental makes assumptions in valuing its assets and liabilities, including assumptions about the risks inherent in the inputs to the valuation technique. For assets and liabilities carried at fair value, Occidental measures fair value using the following methods:
Ø
Commodity derivatives - Occidental values exchange-cleared commodity derivatives using closing prices provided by the exchange as of the balance sheet date. These derivatives are classified as Level 1. Over-the-Counter (OTC) bilateral financial commodity contracts, foreign exchange contracts, options and physical commodity forward purchase and sale contracts are generally valued using quotations provided by brokers or industry-standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility factors, credit risk and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, and can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace. Occidental generally classifies these measurements as Level 2.
Ø
Embedded commodity derivatives - Occidental values embedded commodity derivatives based on a market approach that considers various assumptions, including quoted forward commodity prices and market yield curves. The assumptions used include inputs that are observable and unobservable in the marketplace, and the fair value is designated as Level 3 within the valuation hierarchy.
Occidental generally uses an income approach to measure fair value when there is not a market-observable price for an identical or similar asset or liability. This approach utilizes management's judgments regarding expectations of projected cash flows, and discounts those cash flows using a risk-adjusted discount rate.
Environmental Liabilities and Expenditures
Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Occidental records environmental reserves and related charges and expenses for estimated remediation costs that relate to existing conditions from past operations when environmental remediation efforts are probable and the costs can be reasonably estimated. In determining the reserves and the range of reasonably possible additional losses, Occidental refers to currently available information, including relevant past experience, remedial objectives, available technologies, applicable laws and regulations and cost-sharing arrangements. Occidental bases environmental reserves on management’s estimate of the most likely cost to be incurred, using the most cost-effective technology reasonably expected to achieve the remedial objective. Occidental periodically reviews reserves and adjusts them as new information becomes available. Occidental records environmental reserves on a discounted basis when it deems the aggregate amount and timing of cash payments to be reliably determinable at the time the reserves are established. The reserve methodology with respect to discounting for a specific site is not modified once it is established. The amount of discounted environmental reserves is insignificant. Occidental generally records reimbursements or recoveries of environmental remediation costs in income when received, or when receipt of recovery is highly probable. As of December 31, 2013, 2012 and 2011, Occidental did not have any accruals for reimbursements or recoveries.
Many factors could affect Occidental’s future remediation costs and result in adjustments to its environmental reserves and range of reasonably possible additional losses. The most significant are: (1) cost estimates for remedial activities may be inaccurate; (2) the length of time, type or amount of remediation necessary to achieve the remedial objective may change due to factors such as site conditions, the ability to identify and control contaminant sources or the discovery of additional contamination; (3) a regulatory agency may ultimately reject or modify Occidental’s proposed remedial plan; (4) improved or alternative remediation technologies may change remediation costs; (5) laws and regulations may change remediation requirements or affect cost sharing or allocation of liability; and (6) changes in allocation or cost-sharing arrangements may occur.
Certain sites involve multiple parties with various cost-sharing arrangements, which fall into the following three categories: (1) environmental proceedings that result in a negotiated or prescribed allocation of remediation costs among Occidental and other alleged potentially responsible parties; (2) oil and gas ventures in which each participant pays its proportionate share of remediation costs reflecting its working interest; or (3) contractual arrangements, typically relating to purchases and sales of properties, in which the parties to the transaction agree to methods of allocating remediation costs. In these circumstances, Occidental evaluates the financial viability of other parties with whom it is alleged to be jointly liable, the degree of their commitment to participate and the
consequences to Occidental of their failure to participate when estimating Occidental's ultimate share of liability. Occidental records reserves at its expected net cost of remedial activities and, based on these factors, believes that it will not be required to assume a share of liability of such other potentially responsible parties in an amount materially above amounts reserved.
In addition to the costs of investigations and cleanup measures, which often take in excess of 10 years at NPL sites, Occidental's reserves include management's estimates of the costs to operate and maintain remedial systems. If remedial systems are modified over time in response to significant changes in site-specific data, laws, regulations, technologies or engineering estimates, Occidental reviews and adjusts its reserves accordingly.
If Occidental were to adjust the environmental reserve balance based on the factors described above, the amount of the increase or decrease would be recognized in earnings. For example, if the reserve balance were reduced by 10 percent, Occidental would record a pre-tax gain of $33 million. If the reserve balance were increased by 10 percent, Occidental would record an additional remediation expense of $33 million.
Other Loss Contingencies
Occidental is involved, in the normal course of business, in lawsuits, claims and other legal proceedings and audits. Occidental accrues reserves for these matters when it is probable that a liability has been incurred and the liability can be reasonably estimated. In addition, Occidental discloses, in aggregate, its exposure to loss in excess of the amount recorded on the balance sheet for these matters if it is reasonably possible that an additional material loss may be incurred. Occidental reviews its loss contingencies on an ongoing basis.
Loss contingencies are based on judgments made by management with respect to the likely outcome of these matters and are adjusted as appropriate. Management’s judgments could change based on new information, changes in, or interpretations of, laws or regulations, changes in management’s plans or intentions, opinions regarding the outcome of legal proceedings, or other factors. See "Lawsuits, Claims and Other Contingencies" for additional information.
SIGNIFICANT ACCOUNTING AND DISCLOSURE CHANGES
Listed below are significant recently adopted accounting and disclosure changes.
Offsetting Assets and Liabilities
Beginning in the quarter ended March 31, 2013, Occidental adopted new disclosure requirements relating to its derivatives in accordance with rules issued by the Financial Accounting Standards Board (FASB) in December 2011 and January 2013. These new rules require tabular disclosures of the outstanding derivatives' gross and net fair values, now including those derivatives that are subject to a master netting or similar arrangement and qualify for net presentation, whether or not offset in the consolidated balance sheet.
Reclassification from Accumulated Other Comprehensive Income
Beginning in the quarter ended March 31, 2013, Occidental adopted new disclosure requirements for reporting amounts reclassified out of each component of accumulated other comprehensive income into the income statement in accordance with rules issued by the FASB in February 2013.
These new disclosures were not material to Occidental's financial statements.
DERIVATIVE ACTIVITIES AND MARKET RISK
Commodity Price Risk
General
Occidental’s results are sensitive to fluctuations in oil, NGL and natural gas prices. Price changes at current global prices and levels of production affect Occidental’s pre-tax annual income by approximately $150 million for a $1 per barrel change in oil prices and $30 million for a $1 per barrel change in NGL prices. If domestic natural gas prices varied by $0.50 per Mcf, it would have an estimated annual effect on Occidental's pre-tax income of approximately $100 million. These price-change sensitivities include the impact of PSC and similar contract volume changes on income. If production levels change in the future, the sensitivity of Occidental’s results to prices also will change. The marketing and trading results are sensitive to price changes of oil, gas and, to a lesser degree, other commodities. These sensitivities are additionally dependent on marketing and trading volumes and cannot be predicted reliably.
Occidental’s results are also sensitive to fluctuations in chemical prices. A variation in chlorine and caustic soda prices of $10 per ton would have a pre-tax annual effect on income of approximately $10 million and $30 million, respectively. A variation in PVC prices of $0.01 per lb. would have a pre-tax annual effect on income of approximately $25 million. Historically, over time, product price changes have tracked raw material and feedstock product price changes, somewhat mitigating the effect of price changes on margins. According to IHS Chemical, December 2013 average contract prices were: chlorine-$245 per ton; caustic soda-$583 per ton; and PVC-$0.61 per lb.
Occidental uses derivative instruments, including a combination of short-term futures, forwards, options and swaps, to obtain the average prices for the relevant production month and to improve realized prices for oil and gas. Occidental only occasionally hedges its oil and gas production, and, when it does so, the volumes are usually insignificant. Additionally, Occidental’s Phibro trading unit engages in trading activities using derivatives for the purpose of generating profits mainly from market price changes of commodities.
Risk Management
Occidental conducts its risk management activities for marketing and trading activities under the controls and governance of its risk control policy. The controls under this policy are implemented and enforced by a Risk Management group which manages risk by providing an independent and separate evaluation and check. Members of the Risk Management group report to the Corporate Vice President and Treasurer. The President and Chief Executive Officer, and Executive Vice President of Operations also oversee these controls. Controls for these activities include limits on value at risk, limits on credit, limits on total notional trade value, segregation of duties, delegation of authority, daily price verifications, daily reporting to senior management of positions together with various risk measures and a number of other policy and procedural controls. Additionally, these operations maintain highly liquid positions, as a result of which the market risk typically can be neutralized on short notice.
Fair Value of Marketing and Trading Derivative Contracts
Occidental carries derivative contracts it enters into in connection with its marketing and trading activities at fair value. Fair values for these contracts are derived principally from Level 1 and Level 2 sources.
The following table shows the fair value of Occidental's derivatives (excluding collateral), segregated by maturity periods and by methodology of fair value estimation:
Maturity Periods
Source of Fair Value
Assets/(liabilities)
(in millions)
2015 and 2016
2017 and 2018
and
thereafter
Total
Prices actively quoted
$
(13
)
$
(1
)
$
-
$
-
$
(14
)
Prices provided by other external sources
(5
)
(23
)
-
-
(28
)
Total
$
(18
)
$
(24
)
$
-
$
-
$
(42
)
Note: Includes cash-flow hedges further discussed below.
Cash-Flow Hedges
Occidental entered into financial swap agreements in November 2012 for the sale of a portion of its natural gas production in California. These swap agreements hedge 50 million cubic feet of natural gas per day beginning in January 2013 through March 2014 and qualify as cash-flow hedges. The weighted-average strike price of these swaps is $4.30.
Occidental’s marketing and trading operations store natural gas purchased from third parties at Occidental’s North American leased storage facilities. Derivative instruments are used to fix margins on the future sales of the stored volumes through March 31, 2014. As of December 31, 2013 and 2012, Occidental had approximately 11 billion cubic feet and 20 billion cubic feet of natural gas held in storage, respectively. As of December 31, 2013 and 2012, Occidental had cash-flow hedges for the forecast sale, to be settled by physical delivery, of approximately 13 billion cubic feet and 20 billion cubic feet of this stored natural gas, respectively.
As of December 31, 2013, the total fair value of cash-flow hedges, which was a net liability of $4 million, was included in the total fair value table in "Fair Value of Marketing and Trading Derivative Contracts" above.
Quantitative Information
Occidental uses value at risk to estimate the potential effects of changes in fair values of commodity-based and foreign currency derivatives and commodity contracts used in marketing and trading activities. This method determines the maximum potential negative short-term change in fair value with at least a 95-percent level of confidence. Additionally, Occidental uses trading limits, including, among others, limits on total notional trade value, and maintains liquid positions as a result of which market risk typically can be neutralized on short notice. As a result of these controls, Occidental has determined that the market risk of the marketing and trading activities is not reasonably likely to have a material adverse effect on its operations.
Interest Rate Risk
General
Occidental's exposure to changes in interest rates is not expected to be material and relates to its variable-rate long-term debt obligations. As of December 31, 2013, variable-rate debt constituted approximately 1 percent of Occidental's total debt.
Tabular Presentation of Interest Rate Risk
The table below provides information about Occidental's debt obligations. Debt amounts represent principal payments by maturity date.
Year of Maturity
(in millions of
U.S. dollars)
U.S. Dollar
Fixed-Rate Debt
U.S. Dollar
Variable-Rate Debt
Grand Total (a)
$
-
$
-
$
-
-
-
-
1,450
-
1,450
1,250
-
1,250
-
Thereafter
3,696
3,764
Total
$
6,896
$
$
6,964
Weighted-average interest rate
3.16
%
0.04
%
3.13
%
Fair Value
$
7,062
$
$
7,130
(a)
Excludes unamortized debt discounts of $25 million.
Credit Risk
Occidental's credit risk relates primarily to its derivative financial instruments and trade receivables. Occidental’s contracts are spread among a large number of counterparties. Creditworthiness is reviewed before doing business with a new counterparty and on an ongoing basis. Credit exposure for each customer is monitored for outstanding balances, current activity, and forward mark-to-market exposure.
A substantial portion of Occidental’s derivative transaction volume is executed through exchange-traded contracts, which are subject to nominal credit risk as a significant portion of these transactions is settled on a daily margin basis with select clearinghouses and brokers. Occidental executes the rest of its derivative transactions in the OTC market. Occidental is subject to counterparty credit risk to the extent the counterparty to the derivatives is unable to meet its settlement commitments. Occidental manages this credit risk by selecting counterparties that it believes to be financially strong, by spreading the credit risk among many such counterparties, by entering into master netting arrangements with the counterparties and by requiring collateral, as appropriate. Occidental actively monitors the creditworthiness of each counterparty and records valuation adjustments to reflect counterparty risk, if necessary.
Certain of Occidental's OTC derivative instruments contain credit-risk-contingent features, primarily tied to credit ratings for Occidental or its counterparties, which may affect the amount of collateral that each would need to post. As of December 31, 2013 and 2012, Occidental had a net liability of $8 million and $34 million, respectively, which are net of collateral posted of $23 million and $64 million, respectively. Occidental believes that if it had received a one-notch reduction in its credit ratings, it would not have resulted in a material change in its collateral-posting requirements as of December 31, 2013 and 2012.
As of December 31, 2013, the substantial majority of the credit exposures was with investment grade counterparties. Occidental believes its exposure to credit-related losses at December 31, 2013 was not material and losses associated with credit risk have been insignificant for all years presented.
Foreign Currency Risk
Occidental’s foreign operations have limited currency risk. Occidental manages its exposure primarily by balancing monetary assets and liabilities and limiting cash positions in foreign currencies to levels necessary for operating purposes. A vast majority of international oil sales are denominated in United States dollars. Additionally, all of Occidental’s consolidated foreign oil and gas subsidiaries have the United States dollar as the functional currency. As of December 31, 2013, the fair value of foreign currency derivatives used in the trading operations was immaterial. The effect of exchange rates on transactions in foreign currencies is included in periodic income.
SAFE HARBOR DISCUSSION REGARDING OUTLOOK AND OTHER FORWARD-LOOKING DATA
Portions of this report, including Items 1 and 2 (including the information appearing under the captions “Oil and Gas Operations - Competition,” “Chemical Operations - Competition,” and Midstream and Marketing Operations - Competition”), Item 3, "Legal Proceedings," and Items 7 and 7A (including "Management's Discussion and Analysis of Financial Condition and Results of Operations," including the information under the sub-captions "Strategy," "Oil and Gas Segment -Business Review," “Proved Reserves” and "- Industry Outlook," "Chemical Segment - Industry Outlook," "Midstream, Marketing and Other Segment - Business Review, Gas Processing Plants and CO2 Fields and Facilities" and "- Business Review, Pipeline Transportation," "- Industry Outlook," "Taxes," "Liquidity and Capital Resources," “Contractual Obligations - Delivery Commitments,” "Lawsuits, Claims and Other Contingencies," "Environmental Liabilities and Expenditures," "Critical Accounting Policies and Estimates," and "Derivative Activities and Market Risk"), contain forward-looking statements and involve risks and uncertainties that could materially affect expected results of operations, liquidity, cash flows and business prospects. Words such as "estimate," "project," "predict," "will," "would," "should," "could," "may," "might," "anticipate," "plan," "intend," "believe," "expect," "aim," "goal," "target," "objective," "likely" or similar expressions that convey the prospective nature of events or outcomes generally indicate forward-looking statements. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Occidental does not undertake any obligation to update any forward-looking statements as a result of new information, future events or otherwise. Factors that may cause Occidental’s results of operations and financial position to differ from expectations include items noted in Item 1A "Risk Factors" and elsewhere, and also include the need for final Board of Directors approval of the California separation. Occidental posts or provides links to important information on its website at www.oxy.com.
ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT'S ANNUAL ASSESSMENT OF AND REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Occidental Petroleum Corporation and its subsidiaries (Occidental) is responsible for establishing and maintaining adequate internal control over financial reporting. Occidental’s system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles. Occidental’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of Occidental’s assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that Occidental’s receipts and expenditures are being made only in accordance with authorizations of Occidental’s management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of Occidental’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management has assessed the effectiveness of Occidental’s internal control system as of December 31, 2013, based on the criteria for effective internal control over financial reporting described in Internal Control - Integrated Framework issued in 1992 by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management believes that, as of December 31, 2013, Occidental’s system of internal control over financial reporting is effective.
Occidental’s independent auditors, KPMG LLP, have issued an audit report on Occidental’s internal control over financial reporting.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON CONSOLIDATED FINANCIAL STATEMENTS
To the Board of Directors and Stockholders
Occidental Petroleum Corporation:
We have audited the accompanying consolidated balance sheets of Occidental Petroleum Corporation and subsidiaries (the Company) as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2013. In connection with our audits of the consolidated financial statements, we also have audited financial statement schedule II - valuation and qualifying accounts. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Occidental Petroleum Corporation and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Occidental Petroleum Corporation and subsidiaries' internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework issued in 1992 by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 3, 2014 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Los Angeles, California
March 3, 2014
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING
To the Board of Directors and Stockholders
Occidental Petroleum Corporation:
We have audited Occidental Petroleum Corporation and subsidiaries' (the Company) internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework issued in 1992 by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Assessment of and Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Occidental Petroleum Corporation and its subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework issued in 1992 by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Occidental Petroleum Corporation and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2013, and our report dated March 3, 2014 expressed an unqualified opinion on those consolidated financial statements.
Los Angeles, California
March 3, 2014
Consolidated Balance Sheets
Occidental Petroleum Corporation
and Subsidiaries
In millions
Assets at December 31,
CURRENT ASSETS
Cash and cash equivalents
$
3,393
$
1,592
Trade receivables, net of reserves of $17 in 2013 and $16 in 2012
5,674
4,916
Inventories
1,200
1,344
Other current assets
1,056
1,640
Total current assets
11,323
9,492
INVESTMENTS IN UNCONSOLIDATED ENTITIES
1,459
1,894
PROPERTY, PLANT AND EQUIPMENT
Oil and gas segment
72,367
65,417
Chemical segment
6,446
6,054
Midstream, marketing and other segment
8,684
7,191
Corporate
1,555
1,434
89,052
80,096
Accumulated depreciation, depletion and amortization
(33,231
)
(28,032
)
55,821
52,064
LONG-TERM RECEIVABLES AND OTHER ASSETS, NET
TOTAL ASSETS
$
69,443
$
64,210
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Balance Sheets
Occidental Petroleum Corporation
and Subsidiaries
In millions, except share and per-share amounts
Liabilities and Stockholders’ Equity at December 31,
CURRENT LIABILITIES
Current maturities of long-term debt
$
-
$
Accounts payable
5,520
4,708
Accrued liabilities
2,556
1,966
Domestic and foreign income taxes
Total current liabilities
8,434
7,290
LONG-TERM DEBT, NET
6,939
7,023
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred domestic and foreign income taxes
7,197
6,039
Other
3,501
3,810
10,698
9,849
CONTINGENT LIABILITIES AND COMMITMENTS
STOCKHOLDERS' EQUITY
Common stock, $0.20 per share par value, authorized shares: 1.1 billion, outstanding shares:
2013 - 889,919,058 and 2012 - 888,801,436
Treasury stock: 2013 - 93,928,179 shares and 2012 - 83,287,187 shares
(6,095
)
(5,091
)
Additional paid-in capital
7,515
7,441
Retained earnings
41,831
37,990
Accumulated other comprehensive loss
(303
)
(502
)
Total equity attributable to common stock
43,126
40,016
Noncontrolling interest
Total equity
43,372
40,048
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
$
69,443
$
64,210
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Income
Occidental Petroleum Corporation
and Subsidiaries
In millions, except per-share amounts
For the years ended December 31,
REVENUES AND OTHER INCOME
Net sales
$
24,455
$
24,172
$
23,939
Interest, dividends and other income
Gain on sale of equity investments
1,175
-
-
25,736
24,253
24,119
COSTS AND OTHER DEDUCTIONS
Cost of sales (excludes depreciation, depletion and amortization of $5,341 in 2013, $4,504 in 2012 and $3,584 in 2011)
7,562
7,844
7,385
Selling, general and administrative and other operating expenses
1,801
1,602
1,523
Depreciation, depletion and amortization
5,347
4,511
3,591
Asset impairments and related items
1,751
-
Taxes other than on income
Exploration expense
Interest and debt expense, net
16,454
16,863
13,660
INCOME BEFORE INCOME TAXES AND OTHER ITEMS
9,282
7,390
10,459
Provision for domestic and foreign income taxes
(3,755
)
(3,118
)
(4,201
)
Income from equity investments
INCOME FROM CONTINUING OPERATIONS
5,922
4,635
6,640
Discontinued operations, net
(19
)
(37
)
NET INCOME
$
5,903
$
4,598
$
6,771
BASIC EARNINGS PER COMMON SHARE
Income from continuing operations
$
7.35
$
5.72
$
8.16
Discontinued operations, net
(0.02
)
(0.05
)
0.16
BASIC EARNINGS PER COMMON SHARE
$
7.33
$
5.67
$
8.32
DILUTED EARNINGS PER COMMON SHARE
Income from continuing operations
$
7.34
$
5.71
$
8.16
Discontinued operations, net
(0.02
)
(0.04
)
0.16
DILUTED EARNINGS PER COMMON SHARE
$
7.32
$
5.67
$
8.32
DIVIDENDS PER COMMON SHARE
$
2.56
$
2.16
$
1.84
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Comprehensive Income
Occidental Petroleum Corporation
and Subsidiaries
In millions
For the years ended December 31,
Net income
$
5,903
$
4,598
$
6,771
Other comprehensive income (loss) items:
Foreign currency translation gains (losses)
(25
)
(11
)
Realized foreign currency translation losses
-
-
Unrealized (losses) gains on derivatives (a)
(3
)
Pension and postretirement gains (losses) (b)
(60
)
Reclassification to income of realized (gains) losses on derivatives (c)
(4
)
(24
)
Other comprehensive income (loss), net of tax (d)
(19
)
Comprehensive income
$
6,102
$
4,579
$
6,812
(a)
Net of tax of $2, $(9) and $(7) in 2013, 2012 and 2011, respectively.
(b)
Net of tax of $(101), $(8) and $34 in 2013, 2012 and 2011, respectively. See Note 13, Retirement and Postretirement Benefit Plans, for additional information.
(c)
Net of tax of $2, $14 and $(56) in 2013, 2012 and 2011, respectively.
(d)
There were no other comprehensive income (loss) items related to noncontrolling interests in 2013, 2012 and 2011.
Consolidated Statements of Stockholders' Equity
In millions
Equity Attributable to Common Stock
Common Stock
Treasury Stock
Additional Paid-in Capital
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interest
Total Equity
Balance, December 31, 2010
$
$
(4,228
)
$
7,191
$
29,868
$
(524
)
$
-
$
32,484
Net income
-
-
-
6,771
-
-
6,771
Other comprehensive income, net of tax
-
-
-
-
-
Dividends on common stock
-
-
-
(1,497
)
-
-
(1,497
)
Issuance of common stock and other, net
-
-
-
-
-
Purchases of treasury stock
-
(274
)
-
-
-
-
(274
)
Balance, December 31, 2011
$
$
(4,502
)
$
7,286
$
35,142
$
(483
)
$
-
$
37,620
Net income
-
-
-
4,598
-
-
4,598
Other comprehensive loss, net of tax
-
-
-
-
(19
)
-
(19
)
Dividends on common stock
-
-
-
(1,750
)
-
-
(1,750
)
Issuance of common stock and other, net
-
-
-
-
Noncontrolling interest contributions
-
-
-
-
-
(a)
Purchases of treasury stock
-
(589
)
-
-
-
-
(589
)
Balance, December 31, 2012
$
$
(5,091
)
$
7,441
$
37,990
$
(502
)
$
$
40,048
Net income
-
-
-
5,903
-
-
5,903
Other comprehensive income, net of tax
-
-
-
-
-
Dividends on common stock
-
-
-
(2,062
)
-
-
(2,062
)
Issuance of common stock and other, net
-
-
-
-
-
Noncontrolling interest contributions
-
-
-
-
-
(a)
Purchases of treasury stock
-
(1,004
)
-
-
-
-
(1,004
)
Balance, December 31, 2013
$
$
(6,095
)
$
7,515
$
41,831
$
(303
)
$
$
43,372
(a)
Reflects contributions from the noncontrolling interest in a pipeline company.
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Cash Flows
Occidental Petroleum Corporation
and Subsidiaries
In millions
For the years ended December 31,
CASH FLOW FROM OPERATING ACTIVITIES
Net income
$
5,903
$
4,598
$
6,771
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued operations, net
(131
)
Depreciation, depletion and amortization of assets
5,347
4,511
3,591
Deferred income tax provision
1,187
1,128
1,436
Other noncash charges to income
Asset impairments and related items
1,751
-
Gain on sale of equity investments
(1,175
)
-
-
Undistributed earnings from equity investments
(3
)
(30
)
(33
)
Dry hole expenses
Changes in operating assets and liabilities:
(Increase) decrease in receivables
(755
)
(360
)
Decrease (increase) in inventories
(265
)
(50
)
Decrease in other current assets
Increase (decrease) in accounts payable and accrued liabilities
(1,086
)
Increase (decrease) in current domestic and foreign income taxes
(174
)
Other operating, net
(370
)
Operating cash flow from continuing operations
12,983
11,348
12,306
Operating cash flow from discontinued operations, net of taxes
(56
)
(36
)
(25
)
Net cash provided by operating activities
12,927
11,312
12,281
CASH FLOW FROM INVESTING ACTIVITIES
Capital expenditures
(9,037
)
(10,226
)
(7,518
)
Payments for purchases of assets and businesses
(643
)
(2,490
)
(4,909
)
Sales of equity investments and assets, net
1,619
Other, net
(132
)
(96
)
Investing cash flow from continuing operations
(8,193
)
(12,655
)
(12,473
)
Investing cash flow from discontinued operations
-
-
2,570
Net cash used by investing activities
(8,193
)
(12,655
)
(9,903
)
CASH FLOW FROM FINANCING ACTIVITIES
Payments of long-term debt
(690
)
-
(1,523
)
Proceeds from long-term debt
-
1,736
2,111
Proceeds from issuance of common stock
Purchases of treasury stock
(943
)
(583
)
(274
)
Contributions from (distributions to) noncontrolling interest
(121
)
Cash dividends paid
(1,553
)
(2,128
)
(1,436
)
Other, net
Net cash used by financing activities
(2,933
)
(846
)
(1,175
)
Increase (decrease) in cash and cash equivalents
1,801
(2,189
)
1,203
Cash and cash equivalents - beginning of year
1,592
3,781
2,578
Cash and cash equivalents - end of year
$
3,393
$
1,592
$
3,781
The accompanying notes are an integral part of these consolidated financial statements.
Notes to Consolidated Financial Statements
Occidental Petroleum Corporation
and Subsidiaries
NOTE 1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS
In this report, "Occidental" means Occidental Petroleum Corporation, a Delaware corporation (OPC), or OPC and one or more entities in which it owns a controlling interest (subsidiaries). Occidental conducts its operations through various subsidiaries and affiliates. Occidental's principal businesses consist of the oil and gas, chemical and midstream, marketing and other (midstream and marketing) segments. The oil and gas segment explores for, develops and produces oil and condensate, natural gas liquids (NGL) and natural gas. The chemical segment (OxyChem) mainly manufactures and markets basic chemicals and vinyls. The midstream and marketing segment gathers, processes, transports, stores, purchases and markets oil, condensate, NGLs, natural gas, carbon dioxide (CO2) and power. It also trades around its assets, including transportation and storage capacity, and trades oil, NGLs, gas and other commodities. Additionally, the midstream and marketing segment invests in entities that conduct similar activities.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements have been prepared in conformity with United States generally accepted accounting principles (GAAP) and include the accounts of OPC, its subsidiaries and its undivided interests in oil and gas exploration and production ventures. Occidental accounts for its share of oil and gas exploration and production ventures, in which it has a direct working interest, by reporting its proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on the balance sheets, income statements and cash flow statements.
Certain financial statements, notes and supplementary data for prior years have been reclassified to conform to the 2013 presentation.
INVESTMENTS IN UNCONSOLIDATED ENTITIES
Occidental’s percentage interest in the underlying net assets of affiliates as to which it exercises significant influence without having a controlling interest (excluding oil and gas ventures in which Occidental holds an undivided interest) are accounted for under the equity method. Occidental reviews equity-method investments for impairment whenever events or changes in circumstances indicate that an other-than-temporary decline in value may have occurred. The amount of impairment, if any, is based on quoted market prices, when available, or other valuation techniques, including discounted cash flows.
REVENUE RECOGNITION
Revenue is recognized from oil and gas production when title has passed to the customer, which occurs when the product is shipped. In international locations where oil is shipped by tanker, title passes when the tanker is loaded or product is received by the customer, depending on the shipping terms. This process occasionally causes a difference between actual production in a reporting period and sales volumes that have been recognized as revenue.
Revenue from chemical product sales is recognized when the product is shipped and title has passed to the customer. Certain incentive programs may provide for payments or credits to be made to customers based on the volume of product purchased over a defined period. Total customer incentive payments over a given period are estimated and recorded as a reduction to revenue ratably over the contract period. Such estimates are evaluated and revised as warranted.
Revenue from marketing and trading activities is recognized on net settled transactions upon completion of contract terms and, for physical deliveries, upon title transfer. For unsettled transactions, contracts are recorded at fair value and changes in fair value are reflected in net sales. Revenue from all marketing and trading activities is reported on a net basis.
Occidental records revenue net of any taxes, such as sales taxes, that are assessed by governmental authorities on Occidental's customers.
RISKS AND UNCERTAINTIES
The process of preparing consolidated financial statements in conformity with GAAP requires Occidental's management to make informed estimates and judgments regarding certain types of financial statement balances and disclosures. Such estimates primarily relate to unsettled transactions and events as of the date of the consolidated financial statements and judgments on expected outcomes as well as the materiality of transactions and balances. Changes in facts and circumstances or discovery of new information relating to such transactions and events may result in revised estimates and judgments and actual results may differ from estimates upon settlement. Management believes that these estimates and judgments provide a reasonable basis for the fair presentation of Occidental’s financial statements.
Occidental establishes a valuation allowance against net operating losses and other deferred tax assets to the extent it believes the future benefit from these assets will not be realized in the statutory carryforward periods. Realization of deferred tax assets, including any net operating loss carryforwards, is dependent upon Occidental generating sufficient future taxable income and reversal of temporary differences in jurisdictions where such assets originate.
The accompanying consolidated financial statements include assets of approximately $13.7 billion as of December 31, 2013, and net sales of approximately $8.2 billion for the year ended December 31, 2013, relating to Occidental’s operations in countries outside North America. Occidental operates some of its oil and gas business in countries that occasionally have experienced political instability, nationalizations, corruption, armed conflict, terrorism, insurgency, civil unrest, security problems, labor unrest, OPEC production restrictions, equipment import restrictions and sanctions, all of which increase Occidental's risk of loss or delayed or restricted production or may result in other adverse consequences. Occidental attempts to conduct its affairs so as to mitigate its exposure to such risks and would seek compensation in the event of nationalization.
Because Occidental’s major products are commodities, significant changes in the prices of oil and gas and chemical products may have a significant impact on Occidental’s results of operations.
Also, see "Property, Plant and Equipment" below.
CASH AND CASH EQUIVALENTS
Cash equivalents are short-term, highly liquid investments that are readily convertible to cash. Cash equivalents were approximately $2.9 billion and $1.0 billion at December 31, 2013 and 2012, respectively.
INVESTMENTS
Available-for-sale securities are recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income/loss (AOCI). Trading securities are recorded at fair value with unrealized and realized gains or losses included in net sales.
INVENTORIES
Materials and supplies are valued at weighted-average cost and are reviewed periodically for obsolescence. Oil, NGL and natural gas inventories are valued at the lower of cost or market.
For the chemical segment, Occidental's finished goods inventories are valued at the lower of cost or market. For most of its domestic inventories, other than materials and supplies, the chemical segment uses the last-in, first-out (LIFO) method as it better matches current costs and current revenue. For other countries, Occidental uses the first-in, first-out method (if the costs of goods are specifically identifiable) or the average-cost method (if the costs of goods are not specifically identifiable).
PROPERTY, PLANT AND EQUIPMENT
Oil and Gas
The carrying value of Occidental’s property, plant and equipment (PP&E) represents the cost incurred to acquire or develop the asset, including any asset retirement obligations and capitalized interest, net of accumulated depreciation, depletion and amortization (DD&A) and any impairment charges. For assets acquired, PP&E cost is based on fair values at the acquisition date. Asset retirement obligations and interest costs incurred in connection with qualifying capital expenditures are capitalized and amortized over the lives of the related assets.
Occidental uses the successful efforts method to account for its oil and gas properties. Under this method, Occidental capitalizes costs of acquiring properties, costs of drilling successful exploration wells and development costs. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. If proved reserves have been found, the costs of exploratory wells remain capitalized. Otherwise, Occidental charges the costs of the related wells to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Occidental generally expenses the costs of such exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete.
The following table summarizes the activity of capitalized exploratory well costs for continuing operations for the years ended December 31:
In millions
Balance - Beginning of Year
$
$
$
Additions to capitalized exploratory well costs pending the determination of proved reserves
Reclassifications to property, plant and equipment based on the determination of proved reserves
(271
)
(389
)
(201
)
Capitalized exploratory well costs charged to expense
(50
)
(76
)
(20
)
Balance - End of Year
$
$
$
Occidental expenses annual lease rentals, the costs of injectants used in production and geological, geophysical and seismic costs as incurred.
Occidental determines depreciation and depletion of oil and gas producing properties by the unit-of-production method. It amortizes acquisition costs over total proved reserves, and capitalized development and successful exploration costs over proved developed reserves.
Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Occidental has no proved oil and gas reserves for which the determination of economic producibility is subject to the completion of major additional capital expenditures.
Additionally, Occidental performs impairment tests with respect to its proved properties when product prices decline other than temporarily, reserve estimates change significantly, other significant events occur or management's plans change with respect to these properties in a manner that may impact Occidental's ability to realize the recorded asset amounts. Impairment tests incorporate a number of assumptions involving expectations of undiscounted future cash flows, which can change significantly over time. These assumptions include estimates of future product prices, which Occidental bases on forward price curves and, when applicable, contractual prices, estimates of oil and gas reserves and estimates of future expected operating and development costs. Any impairment loss would be calculated as the excess of the asset's net book value over its estimated fair value.
A portion of the carrying value of Occidental’s oil and gas properties is attributable to unproved properties. At December 31, 2013, the net capitalized costs attributable to unproved properties were $3.6 billion. The unproved amounts are not subject to DD&A until they are classified as proved properties. As exploration and development work progresses, if reserves on these properties are proved, capitalized costs attributable to the properties become subject to DD&A. If the exploration and development work were to be unsuccessful, or management decided not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions or other factors, the capitalized costs of the related properties would be expensed. The timing of any writedowns of these unproved properties, if warranted, depends upon management's plans, the nature, timing and extent of future exploration and development activities and their results. Occidental believes its current plans and exploration and development efforts will allow it to realize its unproved property balance.
Chemical
Occidental’s chemical assets are depreciated using either the unit-of-production or the straight-line method, based upon the estimated useful lives of the facilities. The estimated useful lives of Occidental’s chemical assets, which range from three years to 50 years, are also used for impairment tests. The estimated useful lives for the chemical facilities are based on the assumption that Occidental will provide an appropriate level of annual expenditures to ensure productive capacity is sustained. Such expenditures consist of ongoing routine repairs and maintenance, as well as planned major maintenance activities (PMMA). Ongoing routine repairs and maintenance expenditures are expensed as incurred. PMMA costs are capitalized and amortized over the period until the next planned overhaul. Additionally, Occidental incurs capital expenditures that extend the remaining useful lives of existing assets, increase their capacity or operating efficiency beyond the original specification or add value through modification for a different use. These capital expenditures are not considered in the initial determination of the useful lives of these assets at the time they are placed into service. The resulting revision, if any, of the asset’s estimated useful life is measured and accounted for prospectively.
Without these continued expenditures, the useful lives of these assets could decrease significantly. Other factors that could change the estimated useful lives of Occidental’s chemical assets include sustained higher or lower product prices, which are particularly affected by both domestic and foreign competition, demand, feedstock costs, energy prices, environmental regulations and technological changes.
Occidental performs impairment tests on its chemical assets whenever events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or when management’s plans change with respect to those assets. Any impairment loss would be calculated as the excess of the asset’s net book value over its estimated fair value.
Midstream and Marketing
Occidental’s midstream and marketing PP&E is depreciated over the estimated useful lives of the assets, using either the unit-of-production or straight-line method.
Occidental performs impairment tests on its midstream and marketing assets whenever events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or when management’s plans change with respect to those assets. Any impairment loss would be calculated as the excess of the asset’s net book value over its estimated fair value.
FAIR VALUE MEASUREMENTS
Occidental has categorized its assets and liabilities that are measured at fair value in a three-level fair value hierarchy, based on the inputs to the valuation techniques: Level 1 - using quoted prices in active markets for the assets or liabilities; Level 2 - using observable inputs other than quoted prices for the assets or liabilities; and Level 3 - using unobservable inputs. Transfers between levels, if any, are reported at the end of each reporting period.
Fair Values - Recurring
Occidental primarily applies the market approach for recurring fair value measurements, maximizes its use of observable inputs and minimizes its use of unobservable inputs. Occidental utilizes the mid-point between bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, Occidental makes assumptions in valuing its assets and liabilities, including assumptions about the risks inherent in the inputs to the valuation technique. For assets and liabilities carried at fair value, Occidental measures fair value using the following methods:
Ø
Commodity derivatives - Occidental values exchange-cleared commodity derivatives using closing prices provided by the exchange as of the balance sheet date. These derivatives are classified as Level 1. Over-the-Counter (OTC) bilateral financial commodity contracts, foreign exchange contracts, options and physical commodity forward purchase and sale contracts are generally valued using quotations provided by brokers or industry-standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility factors, credit risk and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace. Occidental classifies these measurements as Level 2.
Ø
Embedded commodity derivatives - Occidental values embedded commodity derivatives based on a market approach that considers various assumptions, including quoted forward commodity prices and market yield curves. The assumptions used include inputs that are observable and unobservable in the marketplace, and the fair value is designated as Level 3 within the valuation hierarchy.
Occidental generally uses an income approach to measure fair value when there is not a market-observable price for an identical or similar asset or liability. This approach utilizes management's judgments regarding expectations of projected cash flows, and discounts those cash flows using a risk-adjusted discount rate.
ACCRUED LIABILITIES-CURRENT
Accrued liabilities include accrued payroll, commissions and related expenses of $459 million and $385 million at December 31, 2013 and 2012, respectively.
ENVIRONMENTAL LIABILITIES AND EXPENDITURES
Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Occidental records environmental reserves and related charges and expenses for estimated remediation costs that relate to existing conditions from past operations when environmental remediation efforts are probable and the costs can be reasonably estimated. In determining the reserves and the range of reasonably possible additional losses, Occidental refers to currently available information, including relevant past experience, remedial objectives, available technologies, applicable laws and regulations and cost-sharing arrangements. Occidental bases environmental reserves on management’s estimate of the most likely cost to be incurred, using the most cost-effective technology reasonably expected to achieve the remedial objective. Occidental periodically reviews reserves and adjusts them as new information becomes available. Occidental records environmental reserves on a discounted basis when it deems the aggregate amount and timing of cash payments to be reliably determinable at the time the reserves are established. The reserve methodology with respect to discounting for a specific site is not modified once it is established. The amount of discounted environmental reserves is insignificant. Occidental generally records reimbursements or recoveries of environmental remediation costs in income when received, or when receipt of recovery is highly probable. As of December 31, 2013, 2012 and 2011, Occidental did not have any accruals for reimbursements or recoveries.
Many factors could affect Occidental’s future remediation costs and result in adjustments to its environmental reserves and range of reasonably possible additional losses. The most significant are: (1) cost estimates for remedial activities may be inaccurate; (2) the length of time, type or amount of remediation necessary to achieve the remedial objective may change due to factors such as site conditions, the ability to identify and control contaminant sources or the discovery of additional contamination; (3) a regulatory agency may ultimately reject or modify Occidental’s proposed remedial plan; (4) improved or alternative remediation technologies may change remediation costs; (5) laws and regulations may change remediation requirements or affect cost sharing or allocation of liability; and (6) changes in allocation or cost-sharing arrangements may occur.
Certain sites involve multiple parties with various cost-sharing arrangements, which fall into the following three categories: (1) environmental proceedings that result in a negotiated or prescribed allocation of remediation costs among Occidental and other alleged potentially responsible parties; (2) oil and gas ventures in which each participant pays its proportionate share of remediation costs reflecting its working interest; or (3) contractual arrangements, typically relating to purchases and sales of properties, in which the parties to the transaction agree to methods of allocating remediation costs. In these circumstances, Occidental evaluates the financial viability of the other parties with whom it is alleged to be jointly liable, the degree of their commitment to participate and the consequences to Occidental of their failure to participate when estimating Occidental's ultimate share of liability. Occidental records reserves at its expected net cost of remedial activities and, based on these factors, believes that it will not be required to assume a share of liability of such other potentially responsible parties in an amount materially above amounts reserved.
In addition to the costs of investigations and cleanup measures, which often take in excess of 10 years at Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) National Priorities List (NPL) sites, Occidental's reserves include management's estimates of the costs to operate and maintain remedial systems. If remedial systems are modified over time in response to significant changes in site-specific data, laws, regulations, technologies or engineering estimates, Occidental reviews and adjusts its reserves accordingly.
ASSET RETIREMENT OBLIGATIONS
Occidental recognizes the fair value of asset retirement obligations in the period in which a determination is made that a legal obligation exists to dismantle an asset and reclaim or remediate the property at the end of its useful life and the cost of the obligation can be reasonably estimated. The liability amounts are based on future retirement cost estimates and incorporate many assumptions such as time to abandonment, technological changes, future inflation rates and the risk-adjusted discount rate. When the liability is initially recorded, Occidental capitalizes the cost by increasing the related PP&E balances. If the estimated future cost of the asset retirement obligation changes, Occidental records an adjustment to both the asset retirement obligation and PP&E. Over time, the liability is increased and expense is recognized for accretion, and the capitalized cost is depreciated over the useful life of the asset.
At a certain number of its facilities, Occidental has identified conditional asset retirement obligations that are related mainly to plant decommissioning. Occidental does not know or cannot estimate when it may settle these obligations. Therefore, Occidental cannot reasonably estimate the fair value of these liabilities. Occidental will recognize these conditional asset retirement obligations in the periods in which sufficient information becomes available to reasonably estimate their fair values.
The following table summarizes the activity of the asset retirement obligation, of which $1,283 million and $1,212 million is included in deferred credits and other liabilities - other, with the remaining current portion in accrued liabilities at December 31, 2013 and 2012, respectively.
For the years ended December 31, (in millions)
Beginning balance
$
1,266
$
1,089
Liabilities incurred - capitalized to PP&E
Liabilities settled and paid
(72
)
(58
)
Accretion expense
Acquisitions, dispositions and other - changes in PP&E
(10
)
Revisions to estimated cash flows - changes in PP&E
(21
)
Ending balance
$
1,332
$
1,266
DERIVATIVE INSTRUMENTS
Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty. Occidental applies hedge accounting when transactions meet specified criteria for cash-flow hedge treatment and management elects and documents such treatment. Otherwise, any fair value gains or losses are recognized in earnings in the current period. For cash-flow hedges, the gain or loss on the effective portion of the derivative is reported as a component of other comprehensive income (OCI) with an offsetting adjustment to the basis of the item being hedged. Realized gains or losses from cash-flow hedges, and any ineffective portion, are recorded as a component of net sales in the consolidated statements of income. Ineffectiveness is primarily created by a lack of correlation between the hedged item and the hedging instrument due to location, quality, grade or changes in the expected quantity of the hedged item. Gains and losses from derivative instruments are reported net in the consolidated statements of income. There were no fair value hedges as of and during the years ended December 31, 2013, 2012 and 2011.
A hedge is regarded as highly effective such that it qualifies for hedge accounting if, at inception and throughout its life, it is expected that changes in the fair value or cash flows of the hedged item will be offset by 80 to 125 percent of the changes in the fair value or cash flows, respectively, of the hedging instrument. In the case of hedging a forecast transaction, the transaction must be probable and must present an exposure to variations in cash flows that could ultimately affect reported net income or loss. Occidental discontinues hedge accounting when it determines that a derivative has ceased to be highly effective as a hedge; when the hedged item matures or is sold or repaid; or when a forecast transaction is no longer deemed probable.
STOCK-BASED INCENTIVE PLANS
Occidental has established several stockholder-approved stock-based incentive plans for certain employees and directors (Plans) that are more fully described in Note 12. A summary of Occidental’s accounting policy for awards issued under the Plans is as follows.
For cash- and stock-settled restricted stock units or incentive award shares (RSUs), compensation value is initially measured on the grant date using the quoted market price of Occidental’s common stock. For cash- and stock-settled total shareholder return incentives (TSRIs), compensation value is initially measured on the grant date using estimated payout levels derived from the Monte Carlo valuation model. Compensation expense for RSUs and TSRIs is recognized on a straight-line basis over the requisite service periods, which is generally over the awards’ respective vesting or performance periods. Compensation expense for the cash-settled portion of the TSRI awards and related dividends is adjusted quarterly for any changes in stock price and the number of share equivalents expected to be paid based on the relevant performance criteria. For RSUs, compensation expense for the cash-settled portion of the awards is adjusted for changes in the value of the underlying stock on a quarterly basis. All such performance or stock-price-related changes are recognized in periodic compensation expense. The stock-settled portion of these awards is expensed using the initially measured compensation value.
EARNINGS PER SHARE
Occidental's instruments containing rights to nonforfeitable dividends granted in stock-based awards are considered participating securities prior to vesting and, therefore, have been deducted from earnings in computing basic and diluted EPS under the two-class method.
Basic EPS was computed by dividing net income attributable to common stock, net of income allocated to participating securities, by the weighted-average number of common shares outstanding during each period, net of treasury shares and including vested but unissued shares and share units. The computation of diluted EPS reflects the additional dilutive effect of stock options and unvested stock awards.
RETIREMENT AND POSTRETIREMENT BENEFIT PLANS
Occidental recognizes the overfunded or underfunded amounts of its defined benefit pension and postretirement plans in its financial statements using a December 31 measurement date.
Occidental determines its defined benefit pension and postretirement benefit plan obligations based on various assumptions and discount rates. The discount rate assumptions used are meant to reflect the interest rate at which the obligations could effectively be settled on the measurement date. Occidental estimates the rate of return on assets with regard to current market factors but within the context of historical returns. Occidental funds and expenses negotiated pension increases for domestic union employees over the terms of the applicable collective bargaining agreements.
Pension and any postretirement plan assets are measured at fair value. Common stock, preferred stock, publicly registered mutual funds, U.S. government securities and corporate bonds are valued using quoted market prices in active markets when available. When quoted market prices are not available, these investments are valued using pricing models with observable inputs from both active and non-active markets. Common and collective trusts are valued at the fund units' net asset value (NAV) provided by the issuer, which represents the quoted price in a non-active market. Short-term investment funds are valued at the fund units' NAV provided by the issuer.
SUPPLEMENTAL CASH FLOW INFORMATION
Occidental paid United States federal, state and foreign income taxes for continuing operations of approximately $1.8 billion, $2.4 billion and $2.9 billion during the years ended December 31, 2013, 2012 and 2011, respectively. Occidental also paid production, property and other taxes of approximately $792 million, $694 million and $635 million during the years ended December 31, 2013, 2012 and 2011, respectively, substantially all of which was in the United States. Interest paid totaled approximately $238 million, $190 million and $315 million for the years 2013, 2012 and 2011, respectively. The 2011 interest paid included $154 million of debt extinguishment premiums.
FOREIGN CURRENCY TRANSACTIONS
The functional currency applicable to all of Occidental’s foreign oil and gas operations is the United States dollar since cash flows are denominated principally in United States dollars. In Occidental's other operations, Occidental's use of non-United States dollar functional currencies was not material for all years presented. The effect of exchange rates on transactions in foreign currencies is included in periodic income. Occidental reports the exchange rate differences arising from translating foreign-currency-denominated balance sheet accounts to the United States dollar as of the reporting date in other comprehensive income. Exchange-rate gains and losses for continuing operations were not material for all years presented.
NOTE 2
ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS
SUBSEQUENT EVENTS
In February 2014, Occidental entered into an agreement to sell its Hugoton Field operations in Kansas, Oklahoma and Colorado for pre-tax proceeds of $1.4 billion. Occidental’s average net production from the Hugoton Field properties in 2013 was approximately 110 million cubic feet equivalent of natural gas per day, of which approximately 30 percent was oil. Occidental anticipates the transaction will be completed in the second quarter of 2014 and expects to report a gain on the sale. In February 2014, the Board of Directors authorized initiation of efforts to separate its California assets into an independent and separately traded company.
In October 2013, the Board of Directors authorized the pursuit of the sale of a minority interest in the Middle East/North Africa operations, the strategic alternatives for select assets, including oil and gas interests in the Williston Basin, Hugoton Field, Piceance Basin and other Rocky Mountain assets and the sale of a portion of Occidental’s investment in the Plains All-American Pipeline, L.P. (Plains Pipeline). Occidental sold a portion of its equity interest in Plains Pipeline for approximately $1.4 billion, resulting in a pre-tax gain of approximately $1.0 billion.
During the year ended December 31, 2013, Occidental paid approximately $0.5 billion to acquire certain domestic oil and gas properties.
In October 2013, Occidental and Mexichem, S.A.B. de C.V. (Mexichem) formed Ingleside Ethylene, LLC (Ingleside) to build and operate an ethane steam cracking unit capable of producing 1.2 billion pounds of ethylene per year (Cracker), which is expected to begin operating in 2017. With the ethylene produced from the Cracker, Occidental will produce vinyl chloride monomer (VCM), of which Mexichem has contracted to purchase a substantial majority. As of December 31, 2013, Occidental had invested approximately $23 million in Ingleside for its portion of construction costs.
In May 2013, Occidental sold its investment in Carbocloro, a Brazilian chemical facility. Occidental received net proceeds of approximately $270 million and recorded a pre-tax gain of $131 million.
Dr. Ray Irani submitted his resignation as a director, effective as of May 15, 2013, and ceased serving as an executive of Occidental. In addition, certain other employees and several consulting arrangements were terminated during the second quarter. As a result of these developments and actions, Occidental recorded a $55 million pre-tax charge in the second quarter for the estimated costs of Dr. Irani's employment and post-employment benefits, and the termination of other employees and consulting arrangements. Dr. Irani and Occidental have settled all matters relating to his separation. The cost of the settlement was consistent with the estimated charge recorded in the second quarter. Dr. Irani's employment terminated in December 2013.
During the year ended December 31, 2012, Occidental paid approximately $2.3 billion for domestic oil and gas properties in the Permian Basin, Williston Basin, South Texas and California.
In November 2012, Occidental and Magellan Midstream Partners, L.P. (Magellan) formed BridgeTex Pipeline Company, LLC (BridgeTex) and are proceeding with construction of the BridgeTex Pipeline, which is expected to begin service in mid-2014. The approximately 450-mile-long pipeline will be capable of transporting approximately 300,000 barrels per day of crude oil between the Permian region (Colorado City, Texas) and Gulf Coast refinery markets. The BridgeTex Pipeline project also includes construction of approximately 2.6 million barrels of oil storage in aggregate.
Occidental owns a 50 percent interest in BridgeTex and the remaining 50 percent interest is owned by Magellan, which will be the operator. BridgeTex was determined to be a variable interest entity because of the difference between Occidental's economic interests and its decision-making rights. Occidental is the primary beneficiary and consequently consolidates BridgeTex. This investment is not material to Occidental's financial statements. At December 31, 2013 and 2012, the BridgeTex assets and liabilities mainly comprised cash and cash equivalents and PP&E. As of December 31, 2013, BridgeTex's total cash, PP&E and non-controlling amounts (reflecting Magellan's interests) were $82 million, $420 million and $246 million, respectively, and as of December 31, 2012, these amounts were $50 million, $9 million and $32 million, respectively. BridgeTex's assets cannot be used for the obligations of, nor do BridgeTex's creditors have recourse to, OPC or its other subsidiaries.
During the year ended December 31, 2011, Occidental acquired producing properties in South Texas for approximately $1.8 billion. Occidental also acquired approximately $2.6 billion of other domestic oil and gas assets, which included properties in California, as well as the Permian and Williston basins.
In the first quarter of 2011, Occidental completed the sale of its Argentine oil and gas operations.
Internationally, in the first quarter of 2011, Occidental acquired a 40-percent participating interest in the Al Hosn gas project in Abu Dhabi, joining with the Abu Dhabi National Oil Company in a 30-year joint venture agreement. The project is operated by Abu Dhabi Gas Development Company Limited. In May 2011, Occidental paid approximately $500 million for its share of pre-acquisition development expenditures.
In early 2011, Occidental ceased exploration activity and its participation in production operations in Libya due to civil unrest in the country and United States sanctions. As a result, Occidental wrote off the entire amount of the capitalized and suspended exploration costs incurred to date, including lease acquisition costs, of approximately $35 million in the first quarter of 2011. The United States government lifted its sanctions in September 2011 and Occidental resumed its participation in the producing operations at that time.
NOTE 3
ACCOUNTING AND DISCLOSURE CHANGES
RECENTLY ADOPTED ACCOUNTING AND DISCLOSURE CHANGES
Offsetting Assets and Liabilities
Beginning in the quarter ended March 31, 2013, Occidental adopted new disclosure requirements relating to its derivatives in accordance with rules issued by the Financial Accounting Standards Board (FASB) in December 2011 and January 2013. These new rules require tabular disclosures of the outstanding derivatives' gross and net fair values, now including those derivatives that are subject to a master netting or similar arrangement and qualify for net presentation, whether or not offset in the consolidated balance sheet.
Reclassification from Accumulated Other Comprehensive Income
Beginning in the quarter ended March 31, 2013, Occidental adopted new disclosure requirements for reporting amounts reclassified out of each component of accumulated other comprehensive income into the income statement in accordance with rules issued by the FASB in February 2013.
These new disclosures were not material to Occidental's financial statements.
NOTE 4
INVENTORIES
Net carrying values of inventories valued under the LIFO method were approximately $205 million and $185 million at December 31, 2013 and 2012, respectively. Inventories consisted of the following:
Balance at December 31, (in millions)
Raw materials
$
$
Materials and supplies
Finished goods
1,291
1,445
LIFO reserve
(91
)
(101
)
Total
$
1,200
$
1,344
NOTE 5
LONG-TERM DEBT
Long-term debt consisted of the following:
Balance at December 31, (in millions)
4.10% senior notes due 2021
$
1,249
$
1,300
1.75% senior notes due 2017
1,250
1,250
2.70% senior notes due 2023
1,224
1,250
3.125% senior notes due 2022
4.125% senior notes due 2016
2.5% senior notes due 2016
1.45% senior notes due 2013
-
1.50% senior notes due 2018
8.45% senior notes due 2029
9.25% senior debentures due 2019
7.2% senior debentures due 2028
Variable rate bonds due 2030 (0.04% and 0.13% as of December 31, 2013 and 2012, respectively)
8.75% medium-term notes due 2023
6,964
7,654
Less:
Unamortized discount, net
(25
)
(31
)
Current maturities
-
(600
)
Total
$
6,939
$
7,023
Occidental has a bank credit facility (Credit Facility) with a $2.0 billion commitment expiring in 2016. No amounts have been drawn under this Credit Facility. Up to $1.0 billion of the Credit Facility is available in the form of letters of credit. Borrowings under the Credit Facility bear interest at various benchmark rates, including LIBOR, plus a margin based on Occidental's senior debt ratings. Additionally, Occidental paid average annual facility fees of 0.08 percent in 2013 on the total commitment amounts of the Credit Facility.
The Credit Facility provides for the termination of loan commitments and requires immediate repayment of any outstanding amounts if certain events of default occur. The Credit Facility and other debt agreements do not contain material adverse change clauses or debt ratings triggers that could restrict Occidental's ability to borrow or that would permit lenders to terminate their commitments or accelerate debt.
As of December 31, 2013, under the most restrictive covenants of its financing agreements, Occidental had substantial capacity for additional unsecured borrowings, the payment of cash dividends and other distributions on, or acquisitions of, Occidental stock.
In December 2013, all $600 million of the outstanding 1.45-percent senior notes due 2013 matured. In addition, Occidental repurchased approximately $90 million of various senior notes due in 2021 and later.
In June 2012, Occidental issued $1.75 billion of debt which comprised $1.25 billion of 2.70-percent senior unsecured notes due 2023 and $500 million of 1.50-percent senior unsecured notes due 2018. Occidental received net proceeds of approximately $1.74 billion. Interest on the notes will be payable semi-annually in arrears in February and August for each series of notes.
In August 2011, Occidental issued $2.15 billion of debt, which comprised $1.25 billion of 1.75-percent senior unsecured notes due 2017 and $900 million of 3.125-percent senior unsecured notes due 2022. Occidental received net proceeds of approximately $2.1 billion. Interest on the notes is payable semi-annually in arrears in February and August for each series of notes.
In March 2011, Occidental redeemed all $1.0 billion of its outstanding 7-percent senior notes due 2013 and all $368 million of its outstanding 6.75-percent senior notes due 2012. Occidental recorded a $163-million pre-tax charge related to this redemption in the first quarter of 2011.
Occidental has provided guarantees on Dolphin Energy's debt, which are limited to certain political and other events. At December 31, 2013 and 2012, Occidental’s total guarantees were not material and a substantial majority of the amounts consisted of limited recourse guarantees on approximately $354 million and $370 million, respectively, of Dolphin’s debt. The fair value of the guarantees was immaterial.
At December 31, 2013, principal payments on long-term debt aggregated approximately $7.0 billion, of which none is due in 2014 and 2015, $1.5 billion is due in 2016, $1.2 billion is due in 2017, $0.5 billion is due in 2018 and $3.8 billion is due in 2019 and thereafter.
Occidental estimates the fair value of fixed-rate debt based on the quoted market prices for those instruments or on quoted market yields for similarly rated debt instruments, taking into account such instruments' maturities. The estimated fair values of Occidental’s debt at December 31, 2013 and 2012, substantially all of which were classified as Level 1, were approximately $7.1 billion and $8.2 billion, respectively, compared to carrying values of approximately $7.0 billion and $7.6 billion, respectively. Occidental's exposure to changes in interest rates relates primarily to its variable-rate, long-term debt obligations, and is not material. As of December 31, 2013 and 2012, variable-rate debt constituted approximately one percent of Occidental's total debt.
NOTE 6
LEASE COMMITMENTS
Operating lease agreements include leases for transportation equipment, power plants, machinery, terminals, storage facilities, land and office space. Occidental’s operating lease agreements frequently include renewal or purchase options and require the Company to pay for utilities, taxes, insurance and maintenance expenses. At December 31, 2013, future net minimum lease payments for noncancelable operating leases (excluding oil and gas and other mineral leases, utilities, taxes, insurance and maintenance expense) were the following:
In millions
Amount (a)
$
Thereafter
Total minimum lease payments
$
1,166
(a)
These amounts are net of sublease rentals of $3 million, which are to be received in 2014.
Rental expense for operating leases, net of sublease rental income for continuing operations, was $204 million in 2013, $176 million in 2012 and $179 million in 2011. Rental expense was net of sublease income of $3 million in 2013 and $4 million each in 2012 and 2011.
NOTE 7
DERIVATIVES
Objective & Strategy
Occidental uses a variety of derivative instruments, including cash-flow hedges and derivative instruments not designated as hedging instruments, to obtain the average prices for the relevant production month and to improve realized prices for oil and gas. Occidental only occasionally hedges its oil and gas production, and, when it does so, the volumes are usually insignificant. Additionally, Occidental’s Phibro trading unit engages in trading activities using derivatives for the purpose of generating profits mainly from market price changes of commodities.
Refer to Note 1 for Occidental’s accounting policy on derivatives.
Cash-Flow Hedges
Occidental entered into financial swap agreements in November 2012 for the sale of a portion of its natural gas production in California. These swap agreements hedge 50 million cubic feet of natural gas per day beginning in January 2013 through March 2014 and qualify as cash-flow hedges. The weighted-average strike price of these swaps is $4.30.
Through March 31, 2012, Occidental held financial swap agreements related to the sale of 50 million cubic feet per day of its existing natural gas production from the Rocky Mountain region of the United States that qualified as cash-flow hedges at a weighted-average strike price of $6.07.
Through December 31, 2011, Occidental held a series of collar agreements for 12,000 barrels of oil per day of its domestic production that qualified as cash-flow hedges at a weighted-average strike price that ranged from $32.92 to $46.35.
Occidental’s marketing and trading operations store natural gas purchased from third parties at Occidental’s North American leased storage facilities. Derivative instruments are used to fix margins on the future sales of the stored volumes through March 31, 2014. As of December 31, 2013 and 2012, Occidental had approximately 11 billion cubic feet and 20 billion cubic feet of natural gas held in storage, respectively. As of December 31, 2013 and 2012, Occidental had cash-flow hedges for the forecast sale, to be settled by physical delivery, of approximately 13 billion cubic feet and 20 billion cubic feet of this stored natural gas, respectively.
The following table presents the after-tax gains and losses recognized in, and reclassified to income from, AOCI, for derivative instruments classified as cash-flow hedges for the years ended December 31, 2013 and 2012 (in millions):
After-tax
Beginning Balance - AOCI
$
(7
)
$
Unrealized (losses) gains recognized in AOCI
(3
)
Gains reclassified to income
(4
)
(24
)
Ending Balance - AOCI
$
(14
)
$
(7
)
Occidental expects to reclassify an insignificant amount, based on the valuation as of December 31, 2013, of net after-tax derivative losses from AOCI into income during the next 12 months. The gains and losses reclassified to income were recognized in net sales, and the amount of the ineffective portion of cash-flow hedges was immaterial for the years ended December 31, 2013 and 2012.
Derivatives Not Designated as Hedging Instruments
The following table summarizes Occidental's net volumes of outstanding commodity derivatives contracts not designated as hedging instruments, including both financial and physical derivative contracts as of December 31, 2013 and 2012:
Net Outstanding Position
Long / (Short)
Commodity
Oil (million barrels)
(22
)
(4
)
Natural gas (billion cubic feet)
(10
)
(170
)
Precious metals (million troy ounces)
The volumes in the table above exclude contracts tied to index prices, for which the fair value, if any, is minimal at any point in time. These contracts do not expose Occidental to price risk because the contract prices fluctuate with index prices.
In addition, Occidental typically has certain other commodity trading contracts, such as agricultural products, power and other metals, as well as foreign exchange contracts. These contracts were not material to Occidental as of December 31, 2013 and 2012.
Occidental fulfills its short positions through its own production or by third-party purchase contracts. Subsequent to December 31, 2013, Occidental entered into purchase contracts for a substantial portion of the outstanding positions at year-end and has sufficient production capacity and the ability to enter into additional purchase contracts to satisfy the remaining positions.
Approximately $11 million and $49 million of net gains from derivatives not designated as hedging instruments were recognized in net sales for the years ended December 31, 2013 and 2012, respectively.
Fair Value of Derivatives
The following table presents the gross and net fair values of Occidental’s outstanding derivatives as of December 31, 2013 and 2012 (in millions):
December 31, 2013
Asset Derivatives
Balance Sheet Location
Fair Value
Liability Derivatives
Balance Sheet Location
Fair Value
Cash-flow hedges (a)
Commodity contracts
Other current assets
$
-
Accrued liabilities
$
Long-term receivables and other assets, net
-
Deferred credits and other liabilities
-
$
-
$
Derivatives not designated as hedging instruments (a)
Commodity contracts
Other current assets
$
Accrued liabilities
$
Long-term receivables and other assets, net
Deferred credits and other liabilities
Total gross fair value
Less: counterparty netting and cash collateral (b) (d)
(329
)
(364
)
Total net fair value of derivatives
$
$
December 31, 2012
Asset Derivatives
Balance Sheet Location
Fair Value
Liability Derivatives
Balance Sheet Location
Fair Value
Cash-flow hedges (a)
Commodity contracts
Other current assets
$
Accrued liabilities
$
Long-term receivables and other assets, net
-
Deferred credits and other liabilities
$
$
Derivatives not designated as hedging instruments (a)
Commodity contracts
Other current assets
$
Accrued liabilities
$
Long-term receivables and other assets, net
Deferred credits and other liabilities
Total gross fair value
Less: counterparty netting and cash collateral (c) (d)
(301
)
(371
)
Total net fair value of derivatives
$
$
(a)
Fair values are presented at gross amounts, including when the derivatives are subject to master netting arrangements and presented on a net basis in the consolidated balance sheets.
(b)
As of December 31, 2013, collateral received of $11 million has been netted against derivative assets and collateral paid of $46 million has been netted against derivative liabilities.
(c)
As of December 31, 2012, collateral received of $25 million has been netted against derivative assets and collateral paid of $95 million has been netted against derivative liabilities.
(d)
Select clearinghouses and brokers require Occidental to post an initial margin deposit. Collateral, mainly for initial margin, of $103 million and $116 million deposited by Occidental has not been reflected in these derivative fair value tables. This collateral is included in other current assets in the consolidated balance sheets as of December 31, 2013 and 2012, respectively.
See Note 15 for fair value measurement disclosures on derivatives.
Credit Risk
A substantial portion of Occidental’s derivative transaction volume is executed through exchange-traded contracts, which are subject to minimal credit risk as a significant portion of these transactions is settled on a daily margin basis with select clearinghouses and brokers. Occidental executes the rest of its derivative transactions in the OTC market. Occidental is subject to counterparty credit risk to the extent the counterparty to the derivatives is unable to meet its settlement commitments. Occidental manages this credit risk by selecting counterparties that it believes to be financially strong, by spreading the credit risk among many such counterparties, by entering into master netting arrangements with the counterparties and by requiring collateral, as appropriate. Occidental actively monitors the creditworthiness of each counterparty and records valuation adjustments to reflect counterparty risk, if necessary.
Certain of Occidental's OTC derivative instruments contain credit-risk-contingent features, primarily tied to credit ratings for Occidental or its counterparties, which may affect the amount of collateral that each would need to post. As of December 31, 2013 and 2012, Occidental had a net liability of $8 million and $34 million, respectively, which are net of collateral posted of $23 million and $64 million, respectively. Occidental believes that if it had received a one-notch reduction in its credit ratings, it would not have resulted in a material change in its collateral-posting requirements as of December 31, 2013 and 2012.
Foreign Currency Risk
Occidental’s foreign operations have limited currency risk. Occidental manages its exposure primarily by balancing monetary assets and liabilities and limiting cash positions in foreign currencies to levels necessary for operating purposes. A vast majority of international oil sales are denominated in United States dollars. Additionally, all of Occidental’s consolidated foreign oil and gas subsidiaries have the United States dollar as the functional currency. As of December 31, 2013, the fair value of foreign currency derivatives used in the trading operations was immaterial. The effect of exchange rates on transactions in foreign currencies is included in periodic income.
NOTE 8
ENVIRONMENTAL LIABILITIES AND EXPENDITURES
Occidental’s operations are subject to stringent federal, state, local and foreign laws and regulations related to improving or maintaining environmental quality.
ENVIRONMENTAL REMEDIATION
The laws that require or address environmental remediation, including CERCLA and similar federal, state, local and foreign laws, may apply retroactively and regardless of fault, the legality of the original activities or the current ownership or control of sites. OPC or certain of its subsidiaries participate in or actively monitor a range of remedial activities and government or private proceedings under these laws with respect to alleged past practices at operating, closed and third-party sites. Remedial activities may include one or more of the following: investigation involving sampling, modeling, risk assessment or monitoring; cleanup measures including removal, treatment or disposal; or operation and maintenance of remedial systems. The environmental proceedings seek funding or performance of remediation and, in some cases, compensation for alleged property damage, punitive damages, civil penalties, injunctive relief and government oversight costs.
As of December 31, 2013, Occidental participated in or monitored remedial activities or proceedings at 157 sites. The following table presents Occidental’s environmental remediation reserves as of December 31, 2013, 2012 and 2011, the current portion of which is included in accrued liabilities ($78 million in 2013, $80 million in 2012 and $79 million in 2011) and the remainder in deferred credits and other liabilities - other ($252 million in 2013, $264 million in 2012 and $281 million in 2011). The reserves are grouped as environmental remediation sites listed or proposed for listing by the U.S. Environmental Protection Agency on the CERCLA National Priorities List (NPL sites) and three categories of non-NPL sites - third-party sites, Occidental-operated sites and closed or non-operated Occidental sites.
$ amounts in millions
Number of Sites
Reserve
Balance
Number of Sites
Reserve Balance
Number of Sites
Reserve Balance
NPL sites
$
$
$
Third-party sites
Occidental-operated sites
Closed or non-operated Occidental sites
Total
$
$
$
As of December 31, 2013, Occidental’s environmental reserves exceeded $10 million each at 10 of the 157 sites described above, and 108 of the sites had reserves from $0 to $1 million each.
As of December 31, 2013, two sites - a landfill in western New York owned by Occidental and a former facility in New York - accounted for 60 percent of its reserves associated with NPL sites. In connection with a 1986 acquisition, Maxus Energy Corporation has retained the liability and is indemnifying Occidental for 14 of the remaining NPL sites.
As of December 31, 2013, Maxus has also retained the liability and is indemnifying Occidental for 8 of the 74 third-party sites. Three of the remaining 66 third-party sites - a former copper mining and smelting operation in Tennessee, a containment and removal project in Tennessee and an active refinery in Louisiana where Occidental reimburses the current owner for certain remediation activities - accounted for 52 percent of Occidental’s reserves associated with these sites.
Four sites - chemical plants in Kansas, Louisiana and New York and a group of oil and gas properties in the southwestern United States - accounted for 61 percent of the reserves associated with the Occidental-operated sites.
Four other sites - a landfill in western New York, former chemical plants in Tennessee and Delaware and a closed coal mine in Pennsylvania - accounted for 64 percent of the reserves associated with closed or non-operated Occidental sites.
Environmental reserves vary over time depending on factors such as acquisitions or dispositions, identification of additional sites and remedy selection and implementation. The following table presents environmental reserve activity for the past three years:
In millions
Balance - Beginning of Year
$
$
$
Remediation expenses and interest accretion
Changes from acquisitions/dispositions
-
-
Payments
(74
)
(72
)
(73
)
Balance - End of Year
$
$
$
Based on current estimates, Occidental expects to expend funds corresponding to approximately half of the current environmental reserves at the sites described above over the next three to four years and the balance at these sites over the subsequent 10 or more years. Occidental believes its range of reasonably possible additional losses beyond those liabilities recorded for environmental remediation at these sites could be up to $380 million.
ENVIRONMENTAL COSTS
Occidental’s environmental costs, some of which include estimates, are presented below for each segment for each of the years ended December 31:
In millions
Operating Expenses
Oil and Gas
$
$
$
Chemical
Midstream and Marketing
$
$
$
Capital Expenditures
Oil and Gas
$
$
$
Chemical
Midstream and Marketing
$
$
$
Remediation Expenses
Corporate
$
$
$
Operating expenses are incurred on a continual basis. Capital expenditures relate to longer-lived improvements in properties currently operated by Occidental. Remediation expenses relate to existing conditions from past operations.
NOTE 9
LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES
OPC or certain of its subsidiaries are involved, in the normal course of business, in lawsuits, claims and other legal proceedings 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. OPC or certain of its subsidiaries also are involved in proceedings under CERCLA and similar federal, state, local and foreign environmental laws. These environmental proceedings seek funding or performance of remediation and, in some cases, compensation for alleged property damage, punitive damages, civil penalties and injunctive relief. Usually OPC or such subsidiaries are among many companies in these environmental proceedings and have to date been successful in sharing response costs with other financially sound companies. Further, some lawsuits, claims and legal proceedings involve acquired or disposed assets with respect to which a third party or Occidental retains liability or indemnifies the other party for conditions that existed prior to the transaction.
Occidental accrues 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. Occidental has disclosed its reserve balances for environmental matters. Reserve balances for other matters as of December 31, 2013 and 2012, were not material to Occidental's consolidated balance sheets. Occidental also evaluates the amount of reasonably possible losses that it could incur as a result of the matters mentioned above. Occidental has disclosed its range of reasonably possible additional losses for sites where it is a participant in environmental remediation. Occidental believes that other reasonably possible losses that it could incur in excess of reserves accrued on the balance sheet would not be material to its consolidated financial position or results of operations.
During the course of its operations, Occidental is subject to audit by tax authorities for varying periods in various federal, state, local and foreign tax jurisdictions. Although taxable years through 2009 for United States federal income tax purposes have been audited by the United States Internal Revenue Service (IRS) pursuant to its Compliance Assurance Program, subsequent taxable years are currently under review. Additionally, in December 2012, Occidental filed United States federal refund claims for tax years 2008 and 2009 which are subject to IRS review. Taxable years from 2000 through the current year remain subject to examination by foreign and state government tax authorities in certain jurisdictions. In certain of these jurisdictions, tax authorities are in various stages of auditing Occidental’s income taxes. During the course of tax audits, disputes have arisen and other disputes may arise as to facts and matters of law. Occidental believes that the resolution of outstanding tax matters would not have a material adverse effect on its consolidated financial position or results of operations.
OPC, its subsidiaries, or both, have entered into agreements providing for future payments to secure terminal and pipeline capacity, drilling rigs and services, electrical power, steam and certain chemical raw materials. Occidental has certain other commitments under contracts, guarantees and joint ventures, including purchase commitments for goods and services at market-related prices and certain other contingent liabilities. At December 31, 2013, total purchase obligations were $10.0 billion, which included approximately $3.0 billion, $1.7 billion, $1.0 billion, $0.6 billion and $0.8 billion that will be paid in 2014, 2015, 2016, 2017 and 2018, respectively. Included in the purchase obligations are commitments for major fixed and determinable capital expenditures during 2014 and thereafter, which were approximately $2.1 billion.
OPC, its subsidiaries, or both, have indemnified various parties against specified liabilities those parties might incur in the future in connection with purchases and other transactions that they have entered into with Occidental. These indemnities usually are contingent upon the other party incurring liabilities that reach specified thresholds. As of December 31, 2013, Occidental is not aware of circumstances that it believes would reasonably be expected to lead to indemnity claims that would result in payments materially in excess of reserves.
NOTE 10
DOMESTIC AND FOREIGN INCOME TAXES
The domestic and foreign components of income from continuing operations before domestic and foreign income taxes were as follows:
For the years ended December 31, (in millions)
Domestic
Foreign
Total
$
4,930
$
4,747
$
9,677
$
2,117
$
5,636
$
7,753
$
4,806
$
6,035
$
10,841
The provisions (credits) for domestic and foreign income taxes on continuing operations consisted of the following:
For the years ended December 31, (in millions)
United States
Federal
State
and Local
Foreign
Total
Current
$
$
$
2,170
$
2,568
Deferred
1,145
(17
)
1,187
$
1,506
$
$
2,153
$
3,755
Current
$
(401
)
$
$
2,383
$
1,990
Deferred
1,046
1,128
$
$
$
2,424
$
3,118
Current
$
$
$
2,357
$
2,765
Deferred
1,340
1,436
$
1,660
$
$
2,406
$
4,201
The following reconciliation of the United States federal statutory income tax rate to Occidental’s worldwide effective tax rate on income from continuing operations is stated as a percentage of pre-tax income:
For the years ended December 31,
United States federal statutory tax rate
%
%
%
Operations outside the United States
State income taxes, net of federal benefit
Other
(1
)
(1
)
(1
)
Worldwide effective tax rate
%
%
%
The tax effects of temporary differences resulting in deferred income taxes at December 31, 2013 and 2012 were as follows:
Tax effects of temporary differences (in millions)
Deferred Tax Assets
Deferred Tax Liabilities
Deferred Tax Assets
Deferred Tax Liabilities
Property, plant and equipment differences
$
-
$
8,363
$
-
$
7,316
Equity investments, partnerships and foreign subsidiaries
-
-
Environmental reserves
-
-
Postretirement benefit accruals
-
-
Deferred compensation and benefits
-
-
Asset retirement obligations
-
-
Foreign tax credit carryforwards
1,091
-
1,277
-
Other tax credit carryforwards
-
-
-
Federal benefit of state income taxes
-
-
All other
Subtotal
2,697
8,670
3,079
7,828
Valuation allowance
(1,074
)
-
(1,040
)
-
Total deferred taxes
$
1,623
$
8,670
$
2,039
$
7,828
The current portion of total deferred tax assets was $150 million and $250 million as of December 31, 2013 and 2012, respectively, which was reported in other current assets. Total deferred tax assets were $1.6 billion and $2.0 billion as of December 31, 2013 and 2012, respectively, the noncurrent portion of which is netted against deferred tax liabilities. Occidental expects to realize the recorded deferred tax assets, net of any allowances, through future operating income and reversal of temporary differences.
Occidental had, as of December 31, 2013, foreign tax credit carryforwards of $1.1 billion, which expire in varying amounts through 2022, and various state operating loss carryforwards, which have varying carryforward periods through 2025. Occidental's valuation allowance provides for substantially all of the foreign tax credit and state operating loss carryforwards.
A deferred tax liability has not been recognized for temporary differences related to unremitted earnings of certain consolidated foreign subsidiaries aggregating approximately $10.6 billion, net of foreign taxes, at December 31, 2013, as it is Occidental’s intention, generally, to reinvest such earnings permanently. If the earnings of these foreign subsidiaries were not indefinitely reinvested, an additional deferred tax liability of approximately $134 million would be required, assuming utilization of available foreign tax credits.
Discontinued operations include income tax charges of $9 million, $7 million and $86 million in 2013, 2012 and 2011, respectively.
Additional paid-in capital was credited $6 million in 2013, $8 million in 2012 and $14 million in 2011 for an excess tax benefit from the exercise of certain stock-based compensation awards.
As of December 31, 2013, Occidental had liabilities for unrecognized tax benefits of approximately $61 million included in deferred credits and other liabilities - other, all of which, if subsequently recognized, would favorably affect Occidental’s effective tax rate.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
For the years ended December 31, (in millions)
Balance at January 1,
$
$
Additions based on tax positions related to the current year
-
Reductions based on tax positions related to prior years and settlements
(15
)
(7
)
Balance at December 31,
$
$
Management believes it is unlikely that Occidental’s liabilities for unrecognized tax benefits related to existing matters would increase or decrease within the next 12 months by a material amount. Occidental cannot reasonably estimate a range of potential changes in such benefits due to the unresolved nature of the various audits.
Occidental is subject to audit by various tax authorities in varying periods. See Note 9 for a discussion of these matters.
Occidental records estimated potential interest and penalties related to liabilities for unrecognized tax benefits in the provisions for domestic and foreign income taxes and these amounts were not material for the years ended December 31, 2013, 2012 and 2011.
NOTE 11
STOCKHOLDERS' EQUITY
The following is a summary of common stock issuances:
Shares in thousands
Common Stock
Balance, December 31, 2010
885,275
Issued
1,302
Options exercised and other, net
Balance, December 31, 2011
886,809
Issued
1,746
Options exercised and other, net
Balance, December 31, 2012
888,801
Issued
Options exercised and other, net
Balance, December 31, 2013
889,919
TREASURY STOCK
In February 2014, Occidental increased the number of shares authorized for its share repurchase program by 30 million from 95 million shares; however, the program does not obligate Occidental to acquire any specific number of shares and may be discontinued at any time. In 2013 and 2012, respectively, Occidental purchased 10.3 million and 7.2 million shares under the program at an average cost of $94.42 and $77.98 per share.
Additionally, Occidental purchased shares from the trustee of its defined contribution savings plan during each year.
As of December 31, 2013, 2012 and 2011, treasury stock shares numbered 93.9 million, 83.3 million and 75.8 million, respectively.
NONREDEEMABLE PREFERRED STOCK
Occidental has authorized 50,000,000 shares of preferred stock with a par value of $1.00 per share. At December 31, 2013, 2012 and 2011, Occidental had no outstanding shares of preferred stock.
EARNINGS PER SHARE
The following table presents the calculation of basic and diluted EPS for the years ended December 31:
In millions, except per-share amounts
Basic EPS
Income from continuing operations
$
5,922
$
4,635
$
6,640
Discontinued operations, net
(19
)
(37
)
Net income
5,903
4,598
6,771
Less: Net income allocated to participating securities
(13
)
(8
)
(11
)
Net income, net of participating securities
$
5,890
$
4,590
$
6,760
Weighted average number of basic shares
804.1
809.3
812.1
Basic EPS
$
7.33
$
5.67
$
8.32
Diluted EPS
Net income, net of participating securities
$
5,890
$
4,590
$
6,760
Weighted average number of basic shares
804.1
809.3
812.1
Dilutive securities
0.5
0.7
0.8
Total diluted weighted average common shares
804.6
810.0
812.9
Diluted EPS
$
7.32
$
5.67
$
8.32
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Accumulated other comprehensive loss consisted of the following after-tax amounts:
Balance at December 31, (in millions)
Foreign currency translation adjustments
$
(5
)
$
(34
)
Unrealized losses on derivatives
(14
)
(7
)
Pension and post-retirement adjustments (a)
(284
)
(461
)
Total
$
(303
)
$
(502
)
(a)
See Note 13 for further information.
NOTE 12
STOCK-BASED INCENTIVE PLANS
Occidental has established several Plans that allow it to issue stock-based awards including in the form of RSUs, stock options (Options), stock appreciation rights (SARs) and TSRIs. An aggregate of 66 million shares of Occidental common stock were authorized for issuance and approximately 16 million shares had been issued through December 31, 2013. Of the remaining shares, only approximately 20 million shares are available for grants of future awards because a plan provision requires each share covered by an award (other than Options and SARs) to be counted as if three shares were issued in determining the number of shares that are available for future awards. Accordingly, the number of shares available for future awards may be less than 20 million depending on the type of award granted. Additionally, under the plan, the shares available for future awards may increase, depending on the award type, by the number of shares currently unvested or forfeitable, or three times that number as applicable, that (i) fail to vest, (ii) are forfeited or canceled, or (iii) correspond to the portion of any stock-based awards settled in cash.
During 2013, non-employee directors were granted awards for 37,100 shares of restricted stock, a substantial majority of which fully vested on the grant date. Compensation expense for these awards was measured using the quoted market price of Occidental's common stock on the grant date and was fully recognized at that time.
The following table summarizes certain stock-based incentive amounts for the past three years:
For the years ended December 31, (in millions)
Compensation expense
$
$
$
Income tax benefit recognized in the income statement
$
$
$
Intrinsic value of options and stock-settled SARs exercised
$
$
$
Cash paid (a)
$
$
$
Fair value of RSUs and TSRIs vested during the year (b)
$
$
$
(a)
Includes cash paid under the cash-settled portion of the SARs, RSUs and TSRIs.
(b)
As measured on the vesting date for the stock-settled portion of the RSUs and TSRIs.
As of December 31, 2013, unrecognized compensation expense for all unvested stock-based incentive awards, based on year-end valuation, was $205 million. This expense is expected to be recognized over a weighted-average period of 2.0 years.
RSUs
Certain employees are awarded the right to receive RSUs, some of which have performance criteria, and are in the form of, or equivalent in value to, actual shares of Occidental common stock. Depending on their terms, RSUs are settled in cash or stock at the time of vesting. These awards vest ratably over three years, or at the end of two or three years, following the grant date, however, certain of the RSUs are forfeitable if performance objectives are not satisfied by the seventh anniversary of the grant date. For certain three-year RSUs, dividend equivalents are paid during the vesting period. For those awards that cliff vest in two or three years, dividend equivalents are accumulated during the vesting period and are paid when they vest.
The weighted-average, grant-date fair values of cash-settled RSUs granted in 2013, 2012 and 2011 were $89.70, $84.38 and $104.74 per share, respectively. The weighted-average, grant-date fair values of the stock-settled RSUs granted in 2013, 2012, and 2011 were $90.35, $84.81 and $102.97, respectively.
A summary of changes in Occidental’s unvested cash- and stock-settled RSUs during the year ended December 31, 2013 is presented below:
Cash-Settled
Stock-Settled
RSUs
(000's)
Weighted-Average
Grant-Date
Fair Value
RSUs
(000's)
Weighted-Average
Grant-Date
Fair Value
Unvested at January 1
1,332
$
90.27
1,375
$
88.23
Granted
89.70
90.35
Vested
(613
)
89.89
(438
)
84.51
Forfeitures
(73
)
90.26
(123
)
88.59
Unvested at December 31
1,431
90.12
1,607
90.26
TSRIs
Certain executives are awarded TSRIs that vest at the end of a three-year period following the grant date if performance targets are certified as being met. TSRIs granted in July 2013 and 2012 have payouts that range from 0 to 150 percent of the target award and 0 to 100 percent of the maximum award, respectively, that would settle, once certified, fully in stock. TSRIs granted in July 2011 have payouts that range from 0 to 100 percent of the maximum award that would settle, once certified, 50 percent in stock and 50 percent in cash. Dividend equivalents for TSRIs are accumulated and paid upon vesting for the number of vested shares.
The fair values of TSRIs are initially determined on the grant date using a Monte Carlo simulation model based on Occidental's assumptions, noted in the following table, and the volatility from corresponding peer group companies. The expected life is based on the vesting period (Term). The risk-free interest rate is the implied yield available on zero coupon T-notes (US Treasury Strip) at the time of grant with a remaining term equal to the Term. The dividend yield is the expected annual dividend yield over the Term, expressed as a percentage of the stock price on the grant date. Estimates of fair value may not accurately predict the value ultimately realized by the employees who receive the awards, and the ultimate value may not be indicative of the reasonableness of the original estimates of fair value made by Occidental.
The grant-date assumptions used in the Monte Carlo simulation models for the estimated payout level of TSRIs were as follows:
TSRIs
Year Granted
Assumptions used:
Risk-free interest rate
0.6
%
0.4
%
0.6
%
Dividend yield
2.8
%
2.6
%
1.8
%
Volatility factor
%
%
%
Expected life (years)
Grant-date fair value of underlying Occidental common stock
$
91.97
$
84.57
$
102.97
A summary of Occidental’s unvested TSRIs as of December 31, 2013, and changes during the year ended December 31, 2013, is presented below:
TSRIs
Awards
(000’s)
Weighted-Average
Grant-Date Fair
Value of Occidental Stock
Unvested at January 1 (a)
1,930
$
80.39
Granted (a)
91.97
Vested (a)
(1,143
)
72.44
Forfeitures
(90
)
87.05
Unvested at December 31 (a)
92.49
(a)
Presented at the target or mid-point payouts.
STOCK OPTIONS AND SARs
Certain employees have been granted Options that are settled in stock and SARs that are settled either only in stock or only in cash. No Options or SARs have been granted since 2006 and all outstanding awards are vested. Exercise prices of the Options and SARs were equal to the quoted market value of Occidental’s stock on the grant date. Generally, the Options and SARs vest ratably over three years from the grant date with a maximum term of ten years. These Options and SARs may be forfeited or accelerated under certain circumstances.
The fair value of each Option, stock-settled SAR or cash-settled SAR is initially measured on the grant date using the Black Scholes option valuation model. The expected life is estimated based on the actual weighted-average life of historical exercise activity of the grantee population at the grant date. The volatility factors are based on the historical volatilities of Occidental common stock over the expected lives as estimated on the grant date. The risk-free interest rate is the implied yield available on US Treasury Strips at the grant date with a remaining term equal to the expected life of the measured instrument. The dividend yield is the expected annual dividend yield over the expected life, expressed as a percentage of the stock price on the grant date. Estimates of fair value may not accurately predict the value ultimately realized by employees who receive stock-based incentive awards, and the ultimate value may not be indicative of the reasonableness of the original estimates of fair value made by Occidental.
The following is a summary of Option and SAR transactions during the year ended December 31, 2013:
Cash-Settled
Stock-Settled
SARs
(000's)
Weighted-
Average
Exercise
Price
Weighted-
Average
Remaining
Contractual
Term (yrs)
Aggregate
Intrinsic
Value
(000’s)
SARs &
Options
(000's)
Weighted-
Average
Exercise
Price
Weighted-
Average
Remaining
Contractual
Term (yrs)
Aggregate
Intrinsic
Value
(000’s)
Beginning balance, January 1
$
24.66
$
31.88
Exercised
(142
)
$
24.66
(391
)
$
28.12
Forfeitures
-
$
-
(1
)
$
15.57
Ending balance, December 31
$
24.66
0.5
$
24,783
$
42.11
1.9
$
7,701
Exercisable at December 31
$
24.66
0.5
$
24,783
$
42.11
1.9
$
7,701
OTHER
During 2013, Occidental also granted approximately 160,000 share-equivalents to certain employees that vest at the end of a three-year period beginning January 1, 2014, if performance targets based on returns on assets of the applicable segment or capital employed are certified as being met. These awards are settled in stock at the time of vesting, with payouts that range from 0 to 200 percent of the target award. Dividend equivalents are accumulated and paid upon vesting for the number of vested shares. The weighted-average, grant-date fair value of these awards was $80.98.
NOTE 13
RETIREMENT AND POSTRETIREMENT BENEFIT PLANS
Occidental has various benefit plans for its salaried, domestic union and nonunion hourly, and certain foreign national employees.
DEFINED CONTRIBUTION PLANS
All domestic employees and certain foreign national employees are eligible to participate in one or more of the defined contribution retirement or savings plans that provide for periodic contributions by Occidental based on plan-specific criteria, such as base pay, age, level and employee contributions. Certain salaried employees participate in a supplemental retirement plan that restores benefits lost due to governmental limitations on qualified retirement benefits. The accrued liabilities for the supplemental retirement plan were $166 million and $145 million as of December 31, 2013 and 2012, respectively, and Occidental expensed $140 million in 2013, $137 million in 2012 and $110 million in 2011 under the provisions of these defined contribution and supplemental retirement plans.
DEFINED BENEFIT PLANS
Participation in defined benefit plans is limited and approximately 1,000 domestic and 1,500 foreign national employees, mainly union, nonunion hourly and certain employees that joined Occidental from acquired operations with grandfathered benefits, are currently accruing benefits under these plans.
Pension costs for Occidental’s defined benefit pension plans, determined by independent actuarial valuations, are generally funded by payments to trust funds, which are administered by independent trustees.
POSTRETIREMENT AND OTHER BENEFIT PLANS
Occidental provides medical and dental benefits and life insurance coverage for certain active, retired and disabled employees and their eligible dependents. Occidental generally funds the benefits as they are paid during the year. These benefit costs, including the postretirement costs, were approximately $229 million in 2013, $218 million in 2012 and $194 million in 2011.
OBLIGATIONS AND FUNDED STATUS
The following tables show the amounts recognized in the consolidated balance sheets of Occidental related to its pension and postretirement benefit plans and their funding status, obligations and plan asset fair values (in millions):
Pension Benefits
Postretirement Benefits
As of December 31,
Amounts recognized in the consolidated balance sheet:
Other assets
$
$
$
-
$
-
Accrued liabilities
(6
)
(4
)
(58
)
(59
)
Deferred credits and other liabilities - other
(83
)
(136
)
(958
)
(1,068
)
$
$
(116
)
$
(1,016
)
$
(1,127
)
AOCI included the following after-tax balances:
Net loss
$
$
$
$
Prior service cost
$
$
$
$
For the years ended December 31,
Changes in the benefit obligation:
Benefit obligation - beginning of year
$
$
$
1,127
$
1,092
Service cost - benefits earned during the period
Interest cost on projected benefit obligation
Actuarial (gain) loss
(35
)
(126
)
Foreign currency exchange rate (gain) loss
(5
)
-
-
Benefits paid
(54
)
(57
)
(57
)
(58
)
Settlements
(35
)
(8
)
-
-
Benefit obligation - end of year
$
$
$
1,016
$
1,127
Changes in plan assets:
Fair value of plan assets - beginning of year
$
$
$
-
$
-
Actual return on plan assets
-
-
Foreign currency exchange rate loss
-
(3
)
-
-
Employer contributions
-
-
Benefits paid
(54
)
(57
)
-
-
Settlements
(24
)
(8
)
-
-
Fair value of plan assets - end of year
$
$
$
-
$
-
Funded/(Unfunded) status:
$
$
(116
)
$
(1,016
)
$
(1,127
)
The following table sets forth details of the obligations and assets of Occidental's defined benefit pension plans (in millions):
Accumulated Benefit
Obligation in Excess of
Plan Assets
Plan Assets
in Excess of Accumulated
Benefit Obligation
As of December 31, (in millions)
Projected Benefit Obligation
$
$
$
$
Accumulated Benefit Obligation
$
$
$
$
Fair Value of Plan Assets
$
$
$
$
Occidental does not expect any plan assets to be returned during 2014.
COMPONENTS OF NET PERIODIC BENEFIT COST
The following table sets forth the components of net periodic benefit costs (in millions):
Pension Benefits
Postretirement Benefits
For the years ended December 31, (in millions)
Net periodic benefit costs:
Service cost - benefits earned during the period
$
$
$
$
$
$
Interest cost on projected benefit obligation
Expected return on plan assets
(31
)
(31
)
(33
)
-
-
-
Recognized actuarial loss
Other costs and adjustments
(13
)
-
Net periodic benefit cost
$
$
$
$
$
$
The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $6 million and zero, respectively. The estimated net loss and prior service cost for the defined benefit postretirement plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $24 million and $1 million, respectively.
ADDITIONAL INFORMATION
The following table sets forth the weighted-average assumptions used to determine Occidental's benefit obligation and net periodic benefit cost for domestic plans:
Pension Benefits
Postretirement Benefits
For the years ended December 31,
Benefit Obligation Assumptions:
Discount rate
4.45
%
3.59
%
4.75
%
3.89
%
Rate of compensation increase
4.00
%
4.00
%
-
-
Net Periodic Benefit Cost Assumptions:
Discount rate
3.59
%
4.12
%
3.89
%
4.12
%
Assumed long term rate of return on assets
6.50
%
6.50
%
-
-
Rate of compensation increase
4.00
%
4.00
%
-
-
For domestic pension plans and postretirement benefit plans, Occidental based the discount rate on the Aon/Hewitt AA-AAA Universe yield curve in 2013 and 2012. The weighted-average rate of increase in future compensation levels is consistent with Occidental’s past and anticipated future compensation increases for employees participating in retirement plans that determine benefits using compensation. The assumed long-term rate of return on assets is estimated with regard to current market factors but within the context of historical returns for the asset mix that exists at year end.
For pension plans outside the United States, Occidental based its discount rate on rates indicative of government or investment grade corporate debt in the applicable country, taking into account hyperinflationary environments when necessary. The discount rates used for the foreign pension plans ranged from 1.5 percent to 10.0 percent at both December 31, 2013 and 2012. The average rate of increase in future compensation levels ranged from 1.5 percent to 10.0 percent in 2013, depending on local economic conditions. The expected long-term rate of return on plan assets was 6.5 percent in excess of local inflation in both 2013 and 2012.
The postretirement benefit obligation was determined by application of the terms of medical and dental benefits and life insurance coverage, including the effect of established maximums on covered costs, together with relevant actuarial assumptions and healthcare cost trend rates projected at an assumed U.S. Consumer Price Index (CPI) increase of 2.36 percent and 2.39 percent as of December 31, 2013 and 2012, respectively. Since 1993, participants other than certain union employees have paid for all medical cost increases in excess of increases in the CPI. For those union employees, Occidental projected that healthcare cost trend rates would decrease 0.25 percent per year from 8.0 percent in 2013 until they reach 5.0 percent in 2025, and remain at 5.0 percent thereafter. A 1-percent increase or a 1-percent decrease in these assumed healthcare cost trend rates would result in an increase of $38 million or a reduction of $32 million, respectively, in the postretirement benefit obligation as of December 31, 2013. The annual service and interest costs would not be materially affected by these changes.
The actuarial assumptions used could change in the near term as a result of changes in expected future trends and other factors that, depending on the nature of the changes, could cause increases or decreases in the plan assets and liabilities.
FAIR VALUE OF PENSION PLAN ASSETS
Occidental employs a total return investment approach that uses a diversified blend of equity and fixed-income investments to optimize the long-term return of plan assets at a prudent level of risk. The investments are monitored by Occidental’s Investment Committee in its role as fiduciary. The Investment Committee, consisting of senior Occidental executives, selects and employs various external professional investment management firms to manage specific investments across the spectrum of asset classes. Equity investments are diversified across United States and non-United States stocks, as well as differing styles and market capitalizations. Other asset classes such as private equity and real estate may be used with the goals of enhancing long-term returns and improving portfolio diversification. The target allocation of plan assets is 65 percent equity securities and 35 percent debt securities. Investment performance is measured and monitored on an ongoing basis through quarterly investment portfolio and manager guideline compliance reviews, annual liability measurements and periodic studies.
The fair values of Occidental’s pension plan assets by asset category are as follows (in millions):
Fair Value Measurements at December 31, 2013 Using
Description
Level 1
Level 2
Level 3
Total
Asset Class:
U.S. government securities
$
$
-
$
-
$
Corporate bonds (a)
-
-
Common/collective trusts (b)
-
-
Mutual funds:
Bond funds
-
-
Blend funds
-
-
Value and growth funds
-
-
Common and preferred stocks (c)
-
-
Other
-
Total pension plan assets (d)
$
$
$
$
Fair Value Measurements at December 31, 2012 Using
Description
Level 1
Level 2
Level 3
Total
Asset Class:
U.S. government securities
$
$
-
$
-
$
Corporate bonds (a)
-
-
Common/collective trusts (b)
-
-
Mutual funds:
Bond funds
-
-
Blend funds
-
-
Value and growth funds
-
-
Common and preferred stocks (c)
-
-
Other
-
Total pension plan assets (d)
$
$
$
$
(a)
This category represents investment grade bonds of U.S. and non-U.S. issuers from diverse industries.
(b)
This category includes investment funds that primarily invest in U.S. and non-U.S. common stocks and fixed-income securities.
(c)
This category represents direct investments in common and preferred stocks from diverse U.S. and non-U.S. industries.
(d)
Amounts exclude net payables of approximately $5 million and $6 million as of December 31, 2013 and 2012, respectively.
The activity during the years ended December 31, 2013 and 2012, for the assets using Level 3 fair value measurements was insignificant.
Occidental expects to contribute $6 million in cash to its defined benefit pension plans during 2014.
Estimated future benefit payments, which reflect expected future service, as appropriate, are as follows:
For the years ended December 31, (in millions)
Pension
Benefits
Postretirement Benefits
$
$
$
$
$
$
$
$
$
$
2019 - 2023
$
$
NOTE 14
INVESTMENTS AND RELATED-PARTY TRANSACTIONS
As of December 31, 2013 and 2012, investments in unconsolidated entities comprised $1.5 billion and $1.9 billion of equity-method investments, respectively.
EQUITY INVESTMENTS
As of December 31, 2013, Occidental’s equity investments consisted mainly of an approximate 25-percent interest in Plains Pipeline, a 24.5-percent interest in the stock of Dolphin Energy, and various other partnerships and joint ventures. Equity investments paid dividends of $447 million, $526 million and $349 million to Occidental in 2013, 2012 and 2011, respectively. As of December 31, 2013, cumulative undistributed earnings of equity-method investees since their respective acquisitions totaled approximately $65 million. As of December 31, 2013, Occidental's investments in equity investees exceeded the underlying equity in net assets by approximately $900 million, of which almost $750 million represented goodwill and the remainder comprised intangibles amortized over their estimated useful lives.
The following table presents Occidental’s interest in the summarized financial information of its equity-method investments:
For the years ended December 31, (in millions)
Revenues
$
3,373
$
2,667
$
2,439
Costs and expenses
2,987
2,310
2,046
Net income
$
$
$
As of December 31, (in millions)
Current assets
$
1,813
$
2,242
Non-current assets
$
4,412
$
5,449
Current liabilities
$
1,308
$
1,799
Long-term debt
$
2,506
$
2,833
Other non-current liabilities
$
$
Stockholders’ equity
$
2,248
$
2,811
Occidental’s investment in Dolphin, which was acquired in 2002, consists of two separate economic interests through which Occidental owns (i) a 24.5-percent undivided interest in the upstream operations under an agreement which is proportionately consolidated in the financial statements; and (ii) a 24.5-percent interest in the stock of Dolphin Energy, which operates a pipeline and is accounted for as an equity investment.
In October 2013, Occidental sold a portion of its equity interest in Plains Pipeline for approximately $1.4 billion, resulting in a pre-tax gain of approximately $1.0 billion.
RELATED-PARTY TRANSACTIONS
From time to time, Occidental purchases oil, NGLs, power, steam and chemicals from and sells oil, NGLs, gas, chemicals and power to certain of its equity investees and other related parties at market-related prices. During 2013, 2012 and 2011, Occidental entered into the following related-party transactions and had the following amounts due from or to its related parties:
December 31, (in millions)
Sales (a)
$
$
$
Purchases
$
-
$
$
Services
$
$
$
Advances and amounts due from
$
$
$
Amounts due to
$
$
$
(a)
In 2013, 2012 and 2011, sales of Occidental-produced oil and NGLs to Plains Pipeline accounted for 72 percent, 80 percent and 76 percent of these totals, respectively. Additionally, Occidental conducts marketing and trading activities with Plains Pipeline for oil and NGLs. These transactions are reported in Occidental's income statement on a net margin basis. The sales amounts above include the net margins on such transactions, which were negligible.
NOTE 15
FAIR VALUE MEASUREMENTS
FAIR VALUES - RECURRING
The following tables provide fair value measurement information for assets and liabilities that are measured on a recurring basis as of December 31, 2013 and 2012 (in millions):
Fair Value Measurements at December 31, 2013 Using
Netting and Collateral
Total
Fair Value
Description
Level 1
Level 2
Level 3
Assets:
Commodity derivatives
$
$
$
-
$
(329
)
$
Liabilities:
Commodity derivatives
$
$
$
-
$
(364
)
$
Fair Value Measurements at December 31, 2012 Using
Netting and Collateral
Total
Fair Value
Description
Level 1
Level 2
Level 3
Assets:
Commodity derivatives
$
$
$
-
$
(301
)
$
Liabilities:
Commodity derivatives
$
$
$
-
$
(371
)
$
FAIR VALUES - NONRECURRING
During its annual capital planning process in the fourth quarter of 2013, management determined that it would not pursue development of certain of its non-producing domestic oil and gas acreage based on product prices, availability of transportation capacity to market the products and regulatory and environmental considerations. As a result, Occidental recorded pre-tax impairment charges of $0.6 billion for the acreage.
At year end 2012, Occidental performed impairment tests with respect to its proved and unproved properties due to the negative revisions to certain of its natural gas reserves and the continued deterioration of natural gas prices. In the fourth quarter of 2012, Occidental recorded pre-tax impairment charges of $1.7 billion, almost all of which were for certain assets in Midcontinent, over 90 percent of which were related to natural gas properties, which were acquired more than five years ago on average.
The impairment tests, including the fair value estimation, incorporated a number of assumptions involving expectations of future cash flows. These assumptions included estimates of future product prices, which Occidental based on forward price curves and, where applicable, contractual prices, estimates of oil and gas reserves, estimates of future expected operating and development costs and appropriate discount rates. These properties were impacted by persistently low natural gas prices in the United States changing management's development plans. Occidental used the income approach to measure the fair value of these properties, using inputs categorized as Level 3 in the fair value hierarchy.
FINANCIAL INSTRUMENTS FAIR VALUE
The carrying amounts of cash and cash equivalents and other on-balance-sheet financial instruments, other than fixed-rate debt, approximate fair value. The cost, if any, to terminate off-balance-sheet financial instruments is not significant.
NOTE 16
INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS
Occidental conducts its continuing operations through three segments: (1) oil and gas; (2) chemical; and (3) midstream and marketing. The oil and gas segment explores for, develops and produces oil and condensate, NGLs, and natural gas. The chemical segment mainly manufactures and markets basic chemicals and vinyls. The midstream and marketing segment gathers, processes, transports, stores, purchases and markets oil, condensate, NGLs, natural gas, CO2 and power. It also trades around its assets, including transportation and storage capacity, and trades oil, NGLs, gas and other commodities. Additionally, the midstream and marketing segment invests in entities that conduct similar activities.
Earnings of industry segments and geographic areas exclude income taxes, interest income, interest expense, environmental remediation expenses, unallocated corporate expenses and discontinued operations, but include gains and losses from dispositions of segment and geographic area assets and income from the segments' equity investments. Intersegment sales eliminate upon consolidation and are generally made at prices approximating those that the selling entity would be able to obtain in third-party transactions.
Identifiable assets are those assets used in the operations of the segments. Corporate assets consist of cash, certain corporate receivables and PP&E, and an investment in the Joslyn, Canada oil sands project.
Industry Segments
In millions
Oil and Gas
Chemical
Midstream and
Marketing
Corporate
and
Eliminations
Total
YEAR ENDED DECEMBER 31, 2013
Net sales
$
19,132
(a)
$
4,673
(b)
$
1,538
(c)
$
(888
)
$
24,455
Pretax operating profit (loss)
$
7,894
(d)
$
(e)
$
1,573
(f)
$
(533
)
(g,i)
$
9,677
(d,e,f)
Income taxes
-
-
-
(3,755
)
(h,i)
(3,755
)
Discontinued operations, net
-
-
-
(19
)
(19
)
Net income (loss)
$
7,894
$
$
1,573
$
(4,307
)
$
5,903
Investments in unconsolidated entities
$
$
$
1,307
$
$
1,459
Property, plant and equipment additions, net (j)
$
7,106
$
$
1,482
$
$
9,188
Depreciation, depletion and amortization
$
4,753
$
$
$
$
5,347
Total assets
$
46,213
$
3,947
$
14,374
$
4,909
$
69,443
YEAR ENDED DECEMBER 31, 2012
Net sales
$
18,906
(a)
$
4,580
(b)
$
1,399
(c)
$
(713
)
$
24,172
Pretax operating profit (loss)
$
7,095
(d)
$
$
$
(501
)
(g,i)
$
7,753
(d)
Income taxes
-
-
-
(3,118
)
(h,i)
(3,118
)
Discontinued operations, net
-
-
-
(37
)
(37
)
Net income (loss)
$
7,095
$
$
$
(3,656
)
$
4,598
Investments in unconsolidated entities
$
$
$
1,662
$
$
1,894
Property, plant and equipment additions, net (j)
$
8,282
$
$
1,612
$
$
10,350
Depreciation, depletion and amortization
$
3,933
$
$
$
$
4,511
Total assets
$
44,004
$
3,854
$
12,762
$
3,590
$
64,210
YEAR ENDED DECEMBER 31, 2011
Net sales
$
18,419
(a)
$
4,815
(b)
$
1,447
(c)
$
(742
)
$
23,939
Pretax operating profit (loss)
$
10,241
(d)
$
$
$
(709
)
(g,i)
$
10,841
(d)
Income taxes
-
-
-
(4,201
)
(h,i)
(4,201
)
Discontinued operations, net
-
-
-
Net income (loss)
$
10,241
(d)
$
$
$
(4,779
)
$
6,771
Investments in unconsolidated entities
$
$
$
1,812
$
$
2,072
Property, plant and equipment additions, net (j)
$
6,192
$
$
1,120
$
$
7,604
Depreciation, depletion and amortization
$
3,064
$
$
$
$
3,591
Total assets
$
38,967
$
3,754
$
11,962
$
5,361
$
60,044
(See footnotes on next page)
Footnotes:
(a)
Oil sales represented approximately 89 percent, 90 percent and 87 percent of the oil and gas segment net sales for the years ended December 31, 2013, 2012 and 2011, respectively.
(b)
Net sales for the chemical segment comprised the following products:
Basic Chemicals
Vinyls
Other Chemicals
Year ended December 31, 2013
55%
42%
3%
Year ended December 31, 2012
57%
40%
3%
Year ended December 31, 2011
58%
39%
3%
(c)
Net sales for the midstream and marketing segment comprised the following:
Gas Processing
Power
Marketing, Trading,
Transportation and other
Year ended December 31, 2013
51%
36%
13%
Year ended December 31, 2012
59%
27%
14%
Year ended December 31, 2011
64%
35%
1%
(d)
The 2013 amount includes pre-tax charges of $607 million for the impairment of domestic non-producing acreage. The 2012 amount includes pre-tax charges of $1.7 billion for the impairment of domestic gas assets and related items. The 2011 amount includes pre-tax charges of $35 million related to exploration write-offs in Libya and $29 million related to a Colombian net worth tax, and a pre-tax gain for the sale of an interest in a Colombian pipeline of $22 million.
(e)
Includes a pre-tax gain of $131 million for the sale of an investment in Carbocloro.
(f)
Includes a pre-tax gain of $1,030 million for the sale of a portion of an investment in Plains Pipeline and other items.
(g)
Includes unallocated net interest expense, administration expense, environmental remediation and other pre-tax items noted in footnote (i) below.
(h)
Includes all foreign and domestic income taxes from continuing operations.
(i)
Includes the following significant items affecting earnings for the years ended December 31:
Benefit (Charge) (In millions)
CORPORATE
Pre-tax operating profit (loss)
Premium on debt extinguishments
$
-
$
-
$
(163
)
Litigation reserves
-
(20
)
-
Charge for former executives and consultants
(55
)
-
-
$
(55
)
$
(20
)
$
(163
)
Income taxes
State income tax charge
$
-
$
-
$
(33
)
Tax effect of pre-tax adjustments *
(179
)
$
(179
)
$
$
* Amounts represent the tax effect of the pre-tax adjustments listed in this note, as well as those in footnotes (d), (e) and (f).
(j) Includes capital expenditures and capitalized interest, but excludes acquisition and disposition of assets.
GEOGRAPHIC AREAS
In millions
Net sales (a)
Property, plant and equipment, net
For the years ended December 31,
United States
$
16,009
$
15,359
$
15,040
$
42,956
$
40,786
$
36,283
Foreign
Qatar
2,995
3,356
3,432
2,605
2,676
2,735
Oman
2,567
2,578
2,500
2,509
2,353
2,143
Colombia
1,022
1,027
1,054
1,259
1,041
United Arab Emirates
-
-
-
3,131
2,104
Other Foreign
1,862
1,852
1,913
3,361
3,104
2,698
Total Foreign
8,446
8,813
8,899
12,865
11,278
9,401
Total
$
24,455
$
24,172
$
23,939
$
55,821
$
52,064
$
45,684
(a)
Sales are shown by individual country based on the location of the entity making the sale.
2013 Quarterly Financial Data (Unaudited)
Occidental Petroleum Corporation
and Subsidiaries
In millions, except per-share amounts
Three months ended
March 31
June 30
September 30
December 31
Segment net sales
Oil and gas
$
4,440
$
4,721
$
5,018
$
4,953
Chemical
1,175
1,187
1,200
1,111
Midstream, marketing and other
Eliminations
(196
)
(215
)
(211
)
(266
)
Net sales
$
5,872
$
5,962
$
6,449
$
6,172
Gross profit
$
2,549
$
2,586
$
3,049
$
2,619
Segment earnings
Oil and gas
$
1,920
$
2,100
$
2,363
$
1,511
(a)
Chemical
(c)
Midstream, marketing and other
1,098
(b)
2,294
2,423
2,756
2,737
Unallocated corporate items
Interest expense, net
(30
)
(29
)
(28
)
(23
)
Income taxes
(844
)
(901
)
(1,037
)
(973
)
Other
(61
)
(166
)
(103
)
(93
)
Income from continuing operations
1,359
1,327
1,588
1,648
Discontinued operations, net
(4
)
(5
)
(5
)
(5
)
Net income
$
1,355
$
1,322
$
1,583
$
1,643
Basic earnings per common share
Income from continuing operations
$
1.69
$
1.65
$
1.97
$
2.05
Discontinued operations, net
(0.01
)
(0.01
)
(0.01
)
(0.01
)
Basic earnings per common share
$
1.68
$
1.64
$
1.96
$
2.04
Diluted earnings per common share
Income from continuing operations
$
1.69
$
1.64
$
1.97
$
2.05
Discontinued operations, net
(0.01
)
-
(0.01
)
(0.01
)
Diluted earnings per common share
$
1.68
$
1.64
$
1.96
$
2.04
Dividends per common share
$
0.64
$
0.64
$
0.64
$
0.64
Market price per common share
High
$
88.74
$
95.57
$
94.50
$
99.42
Low
$
77.21
$
77.91
$
84.91
$
90.13
(a)
Includes fourth quarter pre-tax charges of $607 million related to the impairment of domestic non-producing acreage.
(b)
Includes fourth quarter pre-tax gain of $1,030 million from the sale of a portion of an investment in Plains Pipeline and other items.
(c)
Includes second quarter pre-tax gain of $131 million from the sale of the Carbocloro investment.
2012 Quarterly Financial Data (Unaudited)
Occidental Petroleum Corporation
and Subsidiaries
In millions, except per-share amounts
Three months ended
March 31
June 30
September 30
December 31
Segment net sales
Oil and gas
$
4,902
$
4,495
$
4,635
$
4,874
Chemical
1,148
1,172
1,119
1,141
Midstream, marketing and other
Eliminations
(175
)
(161
)
(178
)
(199
)
Net sales
$
6,268
$
5,768
$
5,965
$
6,171
Gross profit
$
3,144
$
2,541
$
2,617
$
2,842
Segment earnings
Oil and gas
$
2,504
$
2,043
$
2,026
$
(a)
Chemical
Midstream, marketing and other
2,819
2,314
2,344
Unallocated corporate items
Interest expense, net
(28
)
(25
)
(34
)
(30
)
Income taxes
(1,139
)
(875
)
(855
)
(249
)
Other
(92
)
(82
)
(76
)
(134
)
Income from continuing operations
1,560
1,332
1,379
Discontinued operations, net
(1
)
(4
)
(4
)
(28
)
Net income
$
1,559
$
1,328
$
1,375
$
Basic earnings per common share
Income from continuing operations
$
1.92
$
1.64
$
1.70
$
0.45
Discontinued operations, net
-
-
(0.01
)
(0.03
)
Basic earnings per common share
$
1.92
$
1.64
$
1.69
$
0.42
Diluted earnings per common share
Income from continuing operations
$
1.92
$
1.64
$
1.70
$
0.45
Discontinued operations, net
-
-
(0.01
)
(0.03
)
Diluted earnings per common share
$
1.92
$
1.64
$
1.69
$
0.42
Dividends per common share
$
0.54
$
0.54
$
0.54
$
0.54
Market price per common share
High
$
106.68
$
98.24
$
93.60
$
87.39
Low
$
91.85
$
76.59
$
82.25
$
72.43
(a)
Includes fourth quarter pre-tax charges of $1.7 billion for the impairment of domestic gas assets and related items.
Supplemental Oil and Gas Information (Unaudited)
The following tables set forth Occidental’s net interests in quantities of proved developed and undeveloped reserves of oil (including condensate), NGLs and natural gas and changes in such quantities. Reserves are stated net of applicable royalties. Estimated reserves include Occidental's economic interests under production-sharing contracts (PSCs) and other similar economic arrangements. In addition, discussions of oil and gas production or volumes, in general, refer to sales volumes unless the context requires or it is indicated otherwise.
Oil Reserves
In millions of barrels (MMbbl)
United
Latin
Middle East/
States
America
North Africa (a)
Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2010 (b)
1,460
2,012
Revisions of previous estimates
(71
)
(3
)
(60
)
(134
)
Improved recovery
Extensions and discoveries
Purchases of proved reserves
-
-
Sales of proved reserves
-
-
-
-
Production
(84
)
(11
)
(69
)
(164
)
Balance at December 31, 2011
1,526
2,008
Revisions of previous estimates
(70
)
(3
)
(69
)
Improved recovery
Extensions and discoveries
-
Purchases of proved reserves
-
-
Sales of proved reserves
-
-
-
-
Production
(93
)
(11
)
(67
)
(171
)
Balance at December 31, 2012
1,567
2,036
Revisions of previous estimates
(44
)
(5
)
(37
)
Improved recovery
Extensions and discoveries
-
Purchases of proved reserves
-
-
Sales of proved reserves
(4
)
-
-
(4
)
Production
(97
)
(10
)
(65
)
(172
)
Balance at December 31, 2013
1,665
2,147
PROVED DEVELOPED RESERVES
December 31, 2010
1,126
1,561
December 31, 2011
1,146
1,532
December 31, 2012
1,156
1,533
December 31, 2013 (c)
1,187
1,544
PROVED UNDEVELOPED RESERVES
December 31, 2010
December 31, 2011
December 31, 2012
December 31, 2013 (d)
(a)
A substantial majority of the proved reserve amounts relate to PSCs and other similar economic arrangements.
(b)
Excludes proved oil reserves from the Argentine operations sold in February 2011 and classified as discontinued operations of 166 MMbbl as of December 31, 2010.
(c)
Approximately 10 percent of the proved developed reserves at December 31, 2013 are nonproducing, the majority of which are located in the United States.
(d)
The amount of Occidental's proved undeveloped reserves that are not expected to be developed within five years from the date initially recorded was insignificant. A substantial portion of the Middle East/North Africa proved undeveloped reserves at December 31, 2013, was from the Al Hosn gas project in the United Arab Emirates. Occidental expects to transfer a substantial portion of these reserves to the proved developed category at the end of 2014 when additional wells are drilled and initial production begins in the fourth quarter.
NGL Reserves
In millions of barrels (MMbbl)
United
Latin
Middle East/
States
America
North Africa (a)
Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2010
-
Revisions of previous estimates
-
-
(2
)
(2
)
Improved recovery
-
-
Extensions and discoveries
-
-
Purchases of proved reserves
-
-
Sales of proved reserves
-
-
-
-
Production
(25
)
-
(4
)
(29
)
Balance at December 31, 2011
-
Revisions of previous estimates
-
-
Improved recovery
-
-
Extensions and discoveries
-
-
Purchases of proved reserves
-
-
Sales of proved reserves
-
-
-
-
Production
(27
)
-
(3
)
(30
)
Balance at December 31, 2012
-
Revisions of previous estimates
-
(1
)
Improved recovery
-
-
Extensions and discoveries
-
-
Purchases of proved reserves
-
-
Sales of proved reserves
-
-
-
-
Production
(28
)
-
(3
)
(31
)
Balance at December 31, 2013
-
PROVED DEVELOPED RESERVES
December 31, 2010
-
December 31, 2011
-
December 31, 2012
-
December 31, 2013 (b)
-
PROVED UNDEVELOPED RESERVES
December 31, 2010
-
-
December 31, 2011
-
-
December 31, 2012
-
December 31, 2013 (c)
-
(a)
A substantial portion of proved reserve amounts relate to PSCs and other similar economic arrangements.
(b)
Approximately 8 percent of the proved developed reserves at December 31, 2013 are nonproducing, the majority of which are located in the United States.
(c)
The amount of Occidental's proved undeveloped reserves that are not expected to be developed within five years from the date initially recorded was insignificant. The Middle East/North Africa proved undeveloped reserves at December 31, 2013, were from the Al Hosn gas project in the United Arab Emirates. Occidental expects to transfer a substantial portion of these reserves to the proved developed category at the end of 2014 when additional wells are drilled and initial production begins in the fourth quarter.
Gas Reserves
In billions of cubic feet (Bcf)
United
Latin
Middle East/
States
America
North Africa (a)
Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2010 (b)
3,034
2,048
5,138
Revisions of previous estimates
(369
)
(19
)
(78
)
(466
)
Improved recovery
Extensions and discoveries
-
Purchases of proved reserves
-
-
Sales of proved reserves
-
-
-
-
Production
(285
)
(6
)
(156
)
(447
)
Balance at December 31, 2011
3,365
1,925
5,323
Revisions of previous estimates
(748
)
-
(686
)
Improved recovery
Extensions and discoveries
-
Purchases of proved reserves
-
-
Sales of proved reserves
-
-
-
-
Production
(300
)
(5
)
(165
)
(470
)
Balance at December 31, 2012
2,889
2,640
5,568
Revisions of previous estimates
(94
)
(11
)
(43
)
(148
)
Improved recovery
Extensions and discoveries
-
Purchases of proved reserves
-
-
Sales of proved reserves
(2
)
-
-
(2
)
Production
(289
)
(5
)
(158
)
(452
)
Balance at December 31, 2013
2,855
2,687
5,566
PROVED DEVELOPED RESERVES
December 31, 2010
2,007
1,665
3,722
December 31, 2011
2,365
1,555
3,952
December 31, 2012
2,121
1,816
3,973
December 31, 2013 (c)
2,105
1,684
3,812
PROVED UNDEVELOPED RESERVES
December 31, 2010
1,027
1,416
December 31, 2011
1,000
1,371
December 31, 2012
1,595
December 31, 2013 (d)
1,003
1,754
(a)
A substantial majority of proved reserve amounts relate to PSCs and other similar economic arrangements.
(b)
Excludes proved natural gas reserves from the Argentine operations sold in February 2011 and classified as discontinued operations of 182 Bcf as of December 31, 2010.
(c)
Approximately 4 percent of the proved developed reserves at December 31, 2013 are nonproducing, the majority of which are located in the United States.
(d)
The amount of Occidental's proved undeveloped reserves that are not expected to be developed within five years from the date initially recorded was insignificant. The Middle East/North Africa proved undeveloped reserves at December 31, 2013, were from the Al Hosn gas project in the United Arab Emirates. Occidental expects to transfer a substantial portion of these reserves to the proved developed category at the end of 2014 when additional wells are drilled and initial production begins in the fourth quarter.
Total Reserves
In millions of BOE (MMBOE) (a)
United
Latin
Middle East/
States
America
North Africa
Total (b)
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2010 (c)
2,203
3,167
Revisions of previous estimates
(132
)
(7
)
(75
)
(214
)
Improved recovery
Extensions and discoveries
Purchases of proved reserves
-
-
Sales of proved reserves
-
-
-
-
Production
(156
)
(12
)
(99
)
(267
)
Balance at December 31, 2011
2,313
3,176
Revisions of previous estimates
(194
)
(183
)
Improved recovery
Extensions and discoveries
-
Purchases of proved reserves
-
-
Sales of proved reserves
-
-
-
-
Production
(170
)
(12
)
(98
)
(280
)
Balance at December 31, 2012
2,265
3,296
Revisions of previous estimates
(7
)
Improved recovery
Extensions and discoveries
-
Purchases of proved reserves
-
-
Sales of proved reserves
(5
)
-
-
(5
)
Production
(173
)
(11
)
(94
)
(278
)
Balance at December 31, 2013
2,415
3,483
PROVED DEVELOPED RESERVES
December 31, 2010
1,624
2,407
December 31, 2011
1,707
2,412
December 31, 2012
1,677
2,416
December 31, 2013 (d)
1,738
2,431
PROVED UNDEVELOPED RESERVES
December 31, 2010
December 31, 2011
December 31, 2012
December 31, 2013 (e)
1,052
(a)
Natural gas volumes have been converted to barrels of oil equivalent (BOE) based on energy content of six thousand cubic feet (Mcf) of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in 2013, the average prices of West Texas Intermediate (WTI) oil and New York Mercantile Exchange (NYMEX) natural gas were $97.97 per barrel and $3.66 per Mcf, respectively, resulting in an oil to gas ratio of over 25.
(b)
Includes proved reserves related to production-sharing contracts (PSCs) and other similar economic arrangements of 0.9 billion BOE, 0.9 billion BOE, 1.0 billion BOE and 1.1 billion BOE at December 31, 2013, 2012, 2011 and 2010, respectively.
(c)
Excludes proved reserves from the Argentine operations sold in February 2011 and classified as discontinued operations of 196 MMBOE as of December 31, 2010.
(d)
Approximately 8 percent of the proved developed reserves at December 31, 2013 are nonproducing, the majority of which are located in the United States.
(e)
The amount of Occidental's proved undeveloped reserves that are not expected to be developed within five years from the date initially recorded was insignificant. A substantial majority of Middle East/North Africa proved undeveloped reserves at December 31, 2013, was from the Al Hosn gas project in the United Arab Emirates. Occidental expects to transfer a substantial portion of these reserves to the proved developed category at the end of 2014 when additional wells are drilled and initial production begins in the fourth quarter.
,
CAPITALIZED COSTS
Capitalized costs relating to oil and gas producing activities and related accumulated DD&A were as follows:
United
Latin
Middle East/
In millions
States
America
North Africa
Total
December 31, 2013
Proved properties
$
48,172
$
2,485
$
18,090
$
68,747
Unproved properties
3,403
3,620
Total capitalized costs (a)
51,575
2,512
18,280
72,367
Accumulated depreciation, depletion and amortization
(16,388
)
(1,175
)
(10,261
)
(27,824
)
Net capitalized costs
$
35,187
$
1,337
$
8,019
$
44,543
December 31, 2012
Proved properties
$
42,563
$
2,142
$
15,873
$
60,578
Unproved properties
4,592
4,839
Total capitalized costs (a)
47,155
2,169
16,093
65,417
Accumulated depreciation, depletion and amortization
(13,432
)
(1,068
)
(8,582
)
(23,082
)
Net capitalized costs
$
33,723
$
1,101
$
7,511
$
42,335
December 31, 2011
Proved properties
$
36,123
$
1,861
$
13,839
$
51,823
Unproved properties
4,675
-
4,859
Total capitalized costs (a)
40,798
1,861
14,023
56,682
Accumulated depreciation, depletion and amortization
(11,063
)
(951
)
(7,178
)
(19,192
)
Net capitalized costs
$
29,735
$
$
6,845
$
37,490
(a)
Includes acquisition costs, development costs, capitalized interest and asset retirement obligations.
COSTS INCURRED
Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, were as follows:
United
Latin
Middle East/
In millions
States
America
North Africa
Total
FOR THE YEAR ENDED DECEMBER 31, 2013
Property acquisition costs
Proved properties
$
$
-
$
-
$
Unproved properties
-
-
Exploration costs
Development costs
4,203
2,117
6,649
Costs incurred
$
5,175
$
$
2,196
$
7,711
FOR THE YEAR ENDED DECEMBER 31, 2012
Property acquisition costs
Proved properties
$
1,689
$
-
$
$
1,703
Unproved properties
-
-
Exploration costs
Development costs
5,344
2,025
7,673
Costs incurred
$
8,185
$
$
2,153
$
10,643
FOR THE YEAR ENDED DECEMBER 31, 2011
Property acquisition costs
Proved properties
$
3,185
$
-
$
-
$
3,185
Unproved properties
1,311
-
1,343
Exploration costs
Development costs
4,100
1,495
5,809
Costs incurred
$
8,996
$
$
1,614
$
10,857
RESULTS OF OPERATIONS
Occidental’s oil and gas producing activities for continuing operations, which exclude items such as asset dispositions, corporate overhead, interest and royalties, were as follows:
United
Latin
Middle East/
In millions
States
America
North Africa
Total
FOR THE YEAR ENDED DECEMBER 31, 2013
Revenues (a)
$
11,152
$
1,075
$
6,949
$
19,176
Production costs (b)
2,496
1,172
3,826
Other operating expenses
1,126
Depreciation, depletion and amortization
2,967
1,679
4,753
Taxes other than on income
-
Asset impairments and related items
-
-
Exploration expenses
Pretax income
3,378
3,754
7,894
Income tax expense (c)
1,102
1,805
3,163
Results of operations
$
2,276
$
$
1,949
$
4,731
FOR THE YEAR ENDED DECEMBER 31, 2012
Revenues (a)
$
10,379
$
1,085
$
7,486
$
18,950
Production costs (b)
2,963
1,061
4,189
Other operating expenses
Depreciation, depletion and amortization
2,412
1,404
3,933
Taxes other than on income
-
Asset impairments and related items
1,731
-
-
1,731
Exploration expenses
Pretax income
1,676
4,685
7,095
Income tax expense (c)
2,159
2,919
Results of operations
$
1,168
$
$
2,526
$
4,176
FOR THE YEAR ENDED DECEMBER 31, 2011
Revenues (a)
$
9,933
$
1,113
$
7,373
$
18,419
Production costs (b)
2,338
3,428
Other operating expenses
Depreciation, depletion and amortization
1,754
1,220
3,064
Taxes other than on income
-
Exploration expenses
Pretax income
4,490
4,962
10,241
Income tax expense (c)
1,419
2,145
3,834
Results of operations
$
3,071
$
$
2,817
$
6,407
(a)
Revenues are net of royalty payments.
(b)
Production costs are the costs incurred in lifting the oil and gas to the surface and include gathering, primary processing, field storage and insurance on proved properties, but do not include DD&A, royalties, income taxes, interest, general and administrative and other expenses.
(c)
United States federal income taxes reflect certain expenses related to oil and gas activities allocated for United States income tax purposes only, including allocated interest and corporate overhead.
RESULTS PER UNIT OF PRODUCTION FOR CONTINUING OPERATIONS
United
Latin
Middle East/
States
America
North Africa
Total
FOR THE YEAR ENDED DECEMBER 31, 2013
Revenue from each barrel of oil equivalent ($/bbl.) (a,b)
$
64.48
$
100.46
$
73.68
$
68.99
Production costs
14.43
14.76
12.43
13.76
Other operating expenses
4.78
1.96
2.95
4.05
Depreciation, depletion and amortization
17.15
10.00
17.80
17.10
Taxes other than on income
4.01
1.96
-
2.57
Asset impairments and related items
3.51
-
-
2.18
Exploration expenses
1.06
0.56
0.70
0.92
Pretax income
19.54
71.22
39.80
28.41
Income tax expense (c)
6.37
23.92
19.14
11.38
Results of operations
$
13.17
$
47.30
$
20.66
$
17.03
FOR THE YEAR ENDED DECEMBER 31, 2012
Revenue from each barrel of oil equivalent ($/bbl.) (a,b)
$
61.06
$
96.30
$
76.22
$
67.81
Production costs
17.43
14.64
10.80
14.99
Other operating expenses
4.25
3.82
2.28
3.54
Depreciation, depletion and amortization
14.19
10.38
14.30
14.07
Taxes other than on income
3.79
2.04
-
2.39
Asset impairments and related items
10.18
-
-
6.19
Exploration expenses
1.35
0.27
1.14
1.23
Pretax income
9.87
65.15
47.70
25.40
Income tax expense (c)
2.99
22.37
21.98
10.45
Results of operations
$
6.88
$
42.78
$
25.72
$
14.95
FOR THE YEAR ENDED DECEMBER 31, 2011
Revenue from each barrel of oil equivalent ($/bbl.) (a,b)
$
63.56
$
94.19
$
74.58
$
68.99
Production costs
14.96
14.56
9.29
12.84
Other operating expenses
3.74
3.13
2.20
3.14
Depreciation, depletion and amortization
11.22
7.62
12.34
11.48
Taxes other than on income
3.63
1.95
-
2.21
Exploration expenses
1.28
0.17
0.57
0.97
Pretax income
28.73
66.76
50.18
38.35
Income tax expense (c)
9.08
22.85
21.70
14.36
Results of operations
$
19.65
$
43.91
$
28.48
$
23.99
(a)
Natural gas volumes have been converted to BOE based on energy content of six thousand cubic feet (Mcf) of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in 2013, the average prices of WTI oil and NYMEX natural gas were $97.97 per barrel and $3.66 per Mcf, respectively, resulting in an oil to gas ratio of over 25.
(b)
Revenues are net of royalty payments.
(c)
United States federal income taxes reflect certain expenses related to oil and gas activities allocated for United States income tax purposes only, including allocated interest and corporate overhead.
STANDARDIZED MEASURE, INCLUDING YEAR-TO-YEAR CHANGES THEREIN, OF DISCOUNTED FUTURE NET CASH FLOWS
For purposes of the following disclosures, future cash flows were computed by applying to Occidental's proved oil and gas reserves the unweighted arithmetic average of the first-day-of-the-month price for each month within the years ended December 31, 2013, 2012 and 2011, respectively, unless prices were defined by contractual arrangements, and exclude escalations based upon future conditions. The realized prices used to calculate future cash flows vary by producing area and market conditions. Future operating and capital costs were forecast using the current cost environment applied to expectations of future operating and development activities. Future income tax expenses were computed by applying, generally, year-end statutory tax rates (adjusted for permanent differences, tax credits, allowances and foreign income repatriation considerations) to the estimated net future pre-tax cash flows. The discount was computed by application of a 10-percent discount factor. The calculations assumed the continuation of existing economic, operating and contractual conditions at December 31, 2013, 2012 and 2011. Such assumptions, which are required by regulation, have not always proven accurate in the past. Other valid assumptions would give rise to substantially different results.
Standardized Measure of Discounted Future Net Cash Flows
In millions
United
Latin
Middle East/
States
America
North Africa
Total
AT DECEMBER 31, 2013
Future cash inflows
$
174,965
$
9,076
$
50,517
$
234,558
Future costs
Production costs and other operating expenses
(73,092
)
(3,375
)
(13,043
)
(89,510
)
Development costs (a)
(18,365
)
(477
)
(7,084
)
(25,926
)
Future income tax expense
(24,014
)
(1,571
)
(13,182
)
(38,767
)
Future net cash flows
59,494
3,653
17,208
80,355
Ten percent discount factor
(32,035
)
(1,557
)
(6,597
)
(40,189
)
Standardized measure of discounted future net cash flows
$
27,459
$
2,096
$
10,611
$
40,166
AT DECEMBER 31, 2012
Future cash inflows
$
161,821
$
10,574
$
48,914
$
221,309
Future costs
Production costs and other operating expenses
(68,780
)
(3,562
)
(11,922
)
(84,264
)
Development costs (a)
(15,890
)
(541
)
(5,539
)
(21,970
)
Future income tax expense
(21,387
)
(2,023
)
(14,165
)
(37,575
)
Future net cash flows
55,764
4,448
17,288
77,500
Ten percent discount factor
(29,745
)
(1,812
)
(6,656
)
(38,213
)
Standardized measure of discounted future net cash flows
$
26,019
$
2,636
$
10,632
$
39,287
AT DECEMBER 31, 2011
Future cash inflows
$
171,456
$
8,494
$
43,715
$
223,665
Future costs
Production costs and other operating expenses
(69,404
)
(2,807
)
(8,926
)
(81,137
)
Development costs (a)
(13,660
)
(689
)
(3,407
)
(17,756
)
Future income tax expense
(26,175
)
(1,579
)
(15,374
)
(43,128
)
Future net cash flows
62,217
3,419
16,008
81,644
Ten percent discount factor
(32,835
)
(1,415
)
(5,127
)
(39,377
)
Standardized measure of discounted future net cash flows
$
29,382
$
2,004
$
10,881
$
42,267
(a)
Includes asset retirement costs.
Changes in the Standardized Measure of Discounted Future
Net Cash Flows From Proved Reserve Quantities
In millions
For the years ended December 31,
Beginning of year
$
39,287
$
42,267
$
32,737
Sales and transfers of oil and gas produced, net of production costs and other operating expenses
(15,406
)
(14,818
)
(15,243
)
Net change in prices received per barrel, net of production costs and other operating expenses
2,575
(3,005
)
20,325
Extensions, discoveries and improved recovery, net of future production and development costs
6,706
5,625
6,152
Change in estimated future development costs
(4,592
)
(7,330
)
(5,668
)
Revisions of quantity estimates
(537
)
(2,057
)
(3,518
)
Development costs incurred during the period
6,669
7,700
5,797
Accretion of discount
4,617
5,203
4,014
Net change in income taxes
2,087
5,045
(4,776
)
Purchases and sales of reserves in place, net
1,076
3,220
Changes in production rates and other
(1,762
)
(419
)
(773
)
Net change
(2,980
)
9,530
End of year
$
40,166
$
39,287
$
42,267
Average Sales Prices
The following table sets forth, for each of the three years in the period ended December 31, 2013, Occidental’s approximate average sales prices in continuing operations.
United
Latin
Middle East/
States
America (a)
North Africa
Total
Oil
-
Average sales price ($/bbl)
$
96.42
$
103.21
$
104.48
$
99.84
NGLs
-
Average sales price ($/bbl)
$
41.80
$
-
$
33.00
$
41.03
Gas
-
Average sales price ($/mcf)
$
3.37
$
11.17
$
0.76
$
2.54
Oil
-
Average sales price ($/bbl)
$
93.72
$
98.35
$
108.76
$
99.87
NGLs
-
Average sales price ($/bbl)
$
46.07
$
-
$
37.74
$
45.18
Gas
-
Average sales price ($/mcf)
$
2.62
$
11.85
$
0.76
$
2.06
Oil
-
Average sales price ($/bbl)
$
92.80
$
97.16
$
104.34
$
97.92
NGLs
-
Average sales price ($/bbl)
$
59.10
$
-
$
32.09
$
55.53
Gas
-
Average sales price ($/mcf)
$
4.06
$
10.11
$
0.81
$
3.01
(a)
Excludes average sales prices from Argentine operations sold in February 2011 and classified as discontinued operations.
Net Productive and Dry - Exploratory and Development Wells Completed
The following table sets forth, for each of the three years in the period ended December 31, 2013, Occidental’s net productive and dry-exploratory and development wells completed.
United
Latin
Middle East/
States
America (a)
North Africa
Total
Oil
-
Exploratory
27.2
0.8
3.9
31.9
Development
1,161.1
64.0
234.6
1,459.7
Gas
-
Exploratory
1.0
-
0.7
1.7
Development
58.3
2.5
10.4
71.2
Dry
-
Exploratory
12.0
0.8
2.6
15.4
Development
29.9
1.8
0.5
32.2
Oil
-
Exploratory
41.0
-
3.3
44.3
Development
1,183.8
51.8
264.6
1,500.2
Gas
-
Exploratory
3.9
-
-
3.9
Development
134.5
1.0
6.5
142.0
Dry
-
Exploratory
16.5
-
6.1
22.6
Development
31.5
0.4
2.4
34.3
Oil
-
Exploratory
17.7
1.8
2.6
22.1
Development
834.0
57.9
189.3
1,081.2
Gas
-
Exploratory
3.2
-
2.5
5.7
Development
143.1
-
1.1
144.2
Dry
-
Exploratory
13.0
-
1.4
14.4
Development
9.3
-
1.2
10.5
(a)
Excludes for all years presented the exploratory and development wells completed by Argentine operations sold in February 2011 and classified as discontinued operations.
Productive Oil and Gas Wells
The following table sets forth, as of December 31, 2013, Occidental’s productive oil and gas wells (both producing and capable of production).
Wells at
December 31, 2013 (a)
United
States
Latin
America
Middle East/
North Africa
Total
Oil
-
Gross (b)
28,846
(1,994
)
1,415
-
3,474
(729
)
33,735
(2,723
)
Net (c)
25,334
(1,490
)
-
1,822
(351
)
27,859
(1,841
)
Gas
-
Gross (b)
7,508
(376
)
-
(2
)
7,690
(378
)
Net (c)
6,754
(280
)
-
(2
)
6,862
(282
)
(a)
The numbers in parentheses indicate the number of wells with multiple completions.
(b)
The total number of wells in which interests are owned.
(c)
The sum of fractional interests.
Participation in Exploratory and Development Wells Being Drilled
The following table sets forth, as of December 31, 2013, Occidental’s participation in exploratory and development wells being drilled.
Wells at
December 31, 2013
United
States
Latin
America
Middle East/
North Africa
Total
Exploratory and development wells
-
Gross
-
Net
At December 31, 2013, Occidental was participating in 180 pressure-maintenance projects, mostly waterfloods, in the United States, 9 in Latin America and 47 in the Middle East/North Africa.
Oil and Gas Acreage
The following table sets forth, as of December 31, 2013, Occidental’s holdings of developed and undeveloped oil and gas acreage.
Thousands of acres at
United
Latin
Middle East/
December 31, 2013
States (a)
America
North Africa
Total
Developed (b)
-
Gross (c)
8,816
1,335
10,272
-
Net (d)
5,307
5,997
Undeveloped (e)
-
Gross (c)
5,723
6,089
12,180
-
Net (d)
2,906
4,188
7,342
(a)
Includes approximately 2.3 million acres in California, the large majority of which are net fee mineral interests.
(b)
Acres spaced or assigned to productive wells.
(c)
Total acres in which interests are held.
(d)
Sum of the fractional interests owned based on working interests, or interests under PSCs and other economic arrangements.
(e)
Acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether the acreage contains proved reserves.
Occidental’s investment in developed and undeveloped acreage comprises numerous concessions, blocks and leases. Work programs are designed to ensure that the exploration potential of any property is fully evaluated before expiration. In some instances, Occidental may elect to relinquish acreage in advance of the contractual expiration date if the evaluation process is complete and there is not a business basis for extension. In cases where additional time may be required to fully evaluate acreage, Occidental has generally been successful in obtaining extensions. Scheduled lease and concession expirations for undeveloped acreage over the next three years are not expected to have a material adverse impact on Occidental.
Oil, NGLs and Natural Gas Production and Sales Volumes Per Day
The following tables set forth the production and sales volumes of oil, NGLs and natural gas per day for each of the three years in the period ended December 31, 2013. The differences between the production and sales volumes per day are generally due to the timing of shipments at Occidental’s international locations where product is loaded onto tankers.
Production per Day
United States
Oil (MBBL)
California
Permian
Midcontinent and Other
TOTAL
NGLs (MBBL)
California
Permian
Midcontinent and Other
TOTAL
Natural gas (MMCF)
California
Permian
Midcontinent and Other
TOTAL
Latin America (a)
Oil (MBBL) - Colombia
Natural gas (MMCF) - Bolivia
Middle East/North Africa
Oil (MBBL)
Dolphin
Oman
Qatar
Other
TOTAL
NGLs (MBBL)
Dolphin
Other
-
-
TOTAL
Natural gas (MMCF)
Dolphin
Oman
Other
TOTAL
Total Production (MBOE) (a,b)
(See footnotes following the Sales Volumes per Day table)
Sales Volumes per Day
United States
Oil (MBBL)
NGLs (MBBL)
Natural gas (MMCF)
Latin America (a)
Oil (MBBL) - Colombia
Natural gas (MMCF) - Bolivia
Middle East/North Africa
Oil (MBBL)
Dolphin
Oman
Qatar
Other
TOTAL
NGLs (MBBL)
Dolphin
Other
-
-
TOTAL
Natural gas (MMCF)
Total Sales Volumes (MBOE) (a,b)
(a)
For all periods presented, excludes volumes from the Argentine operations sold in February 2011 and classified as discontinued operations.
(b)
Natural gas volumes have been converted to BOE based on energy content of six Mcf of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in 2013, the average prices of WTI oil and NYMEX natural gas were $97.97 per barrel and $3.66 per Mcf, respectively, resulting in an oil to gas ratio of over 25.
Schedule II - Valuation and Qualifying Accounts
Occidental Petroleum Corporation
and Subsidiaries
In millions
Additions
Balance at Beginning of Period
Charged to
Costs and
Expenses
Charged to
Other
Accounts
Deductions (a)
Balance at
End of
Period
Allowance for doubtful accounts
$
$
$
-
$
-
$
Environmental
$
$
$
-
$
(74
)
$
Litigation, tax and other reserves
(70
)
$
$
$
$
(144
)
$
(b)
Allowance for doubtful accounts
$
$
-
$
-
$
-
$
Environmental
$
$
$
-
$
(72
)
$
Litigation, tax and other reserves
-
(26
)
$
$
$
-
$
(98
)
$
(b)
Allowance for doubtful accounts
$
$
-
$
-
$
(3
)
$
Environmental
$
$
$
$
(73
)
$
Litigation, tax and other reserves
-
(32
)
$
$
$
$
(105
)
$
(b)
Note: The amounts presented represent continuing operations.
(a)
Primarily represents payments.
(b)
Of these amounts, $101 million, $98 million and $100 million in 2013, 2012 and 2011, respectively, are classified as current.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
CONTROLS AND PROCEDURES
DISCLOSURE CONTROLS AND PROCEDURES
Occidental's President and Chief Executive Officer and its Executive Vice President and Chief Financial Officer supervised and participated in Occidental's evaluation of its disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (Exchange Act)) as of the end of the period covered by this report. Based upon that evaluation, Occidental's President and Chief Executive Officer and Executive Vice President and Chief Financial Officer concluded that Occidental's disclosure controls and procedures were effective as of December 31, 2013.
There has been no change in Occidental's internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter of 2013 that has materially affected, or is reasonably likely to materially affect, Occidental's internal control over financial reporting. Management’s Annual Assessment of and Report on Occidental’s Internal Control over Financial Reporting and the Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting are set forth in Item 8.
Part III
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Occidental has adopted a Code of Business Conduct (Code). The Code applies to the President and Chief Executive Officer; Executive Vice President and Chief Financial Officer; Vice President, Controller and Principal Accounting Officer; and persons performing similar functions (Key Personnel). The Code also applies to Occidental's directors, its employees and the employees of entities it controls. The Code is posted at www.oxy.com. Occidental will satisfy any disclosure requirement under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, any provision of the Code with respect to its Key Personnel or directors by disclosing the nature of that amendment or waiver on its website.
This item incorporates by reference the information regarding Occidental's directors appearing under the caption "Election of Directors - forepart," and "-Board Committees - Audit Committee," "Security Ownership - Section 16(a) Beneficial Ownership Reporting Compliance," and "General Information - Nominations for Directors for Term Expiring in 2016" in Occidental's definitive Proxy Statement, relating to its May 2, 2014, Annual Meeting of Stockholders (2014 Proxy Statement). The list of Occidental's executive officers and related information under "Executive Officers" set forth in Part I of this report is incorporated by reference herein.
ITEM 11.
EXECUTIVE COMPENSATION
This item incorporates by reference the information appearing under the captions "Compensation Discussion and Analysis," (except "Succession Planning"), "Executive Compensation Tables" and "Director Compensation" in the 2014 Proxy Statement. Pursuant to the rules and regulations under the Exchange Act, the information under the caption "Compensation Discussion and Analysis - Compensation Committee Report" shall not be deemed to be "soliciting material," or to be "filed" with the SEC, or subject to Regulation 14A or 14C under the Exchange Act or to the liabilities of Section 18 of the Exchange Act, nor shall it be deemed incorporated by reference into any filing under the Securities Act of 1933.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
This item incorporates by reference the information with respect to security ownership appearing under the caption "Security Ownership - Certain Beneficial Owners and Management" in the 2014 Proxy Statement. See also the information under "Securities Authorized for Issuance Under Equity Compensation Plans" in Part II, Item 5 of this report.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
This item incorporates by reference the information appearing under the caption "Corporate Governance - Board of Directors and its Committees - Independence", and " - Other Governance Measures - Related Party Transactions" in the 2014 Proxy Statement.
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
This item incorporates by reference the information with respect to accountant fees and services appearing under the caption "Ratification of Independent Auditors - Audit and Other Fees" in the 2014 Proxy Statement.
Part IV
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The agreements included as exhibits to this report are included to provide information about their terms and not to provide any other factual or disclosure information about Occidental or the other parties to the agreements. The agreements contain representations and warranties by each of the parties to the applicable agreement that were made solely for the benefit of the other agreement parties and:
•
should not be treated as categorical statements of fact, but rather as a way of allocating the risk among the parties if those statements prove to be inaccurate;
•
have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;
•
may apply standards of materiality in a way that is different from the way investors may view materiality; and
•
were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.
(a) (1) and (2). Financial Statements and Financial Statement Schedule
Reference is made to Item 8 of the Table of Contents of this report, where these documents are listed.
(a) (3). Exhibits
3.(i)*
Restated Certificate of Incorporation of Occidental, dated November 12, 1999 (filed as Exhibit 3.(i) to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 1999, File No. 1-9210).
3.(i)(a)*
Certificate of Change of Location of Registered Office and of Registered Agent, dated July 6, 2001 (filed as Exhibit 3.1(i) to the Registration Statement on Form S-3 of Occidental, File No. 333-82246).
3.(i)(b)*
Certificate of Amendment of Restated Certificate of Incorporation of Occidental Petroleum Corporation, dated May 5, 2006 (filed as Exhibit 3.(i)(b) to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2006, File No. 1-9210).
3.(i)(c)*
Certificate of Amendment of Restated Certificate of Incorporation of Occidental Petroleum Corporation, dated May 1, 2009 (filed as Exhibit 3.(i)(c) to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2009, File No. 1-9210).
3.(ii)*
Bylaws of Occidental, as amended through May 3, 2013 (filed as Exhibit 3.(ii) to the Current Report on Form 8-K of Occidental dated May 3, 2013 (date of earliest event reported), filed May 8, 2013, File No. 1-9210).
4.1*
Indenture, dated as of August 18, 2011, between Occidental Petroleum and The Bank of New York Mellon Trust Company, N.A. (filed as Exhibit 4.1 to the Current Report on Form 8-K of Occidental dated August 15, 2011 (date of earliest event reported), File No. 1-9210).
4.2*
Indenture (Senior Debt Securities), dated as of April 1, 1998, between Occidental and The Bank of New York, as Trustee (filed as Exhibit 4 to the Registration Statement on Form S-3 of Occidental, File No. 333-52053).
Instruments defining the rights of holders of other long-term debt of Occidental and its subsidiaries are not being filed since the total amount of securities authorized under each of such instruments does not exceed 10 percent of the total assets of Occidental and its subsidiaries on a consolidated basis. Occidental agrees to furnish a copy of any such instrument to the Commission upon request.
All of the Exhibits numbered 10.1 to 10.75 are management contracts and compensatory plans required to be identified specifically as responsive to Item 601(b)(10)(iii)(A) of Regulation S-K pursuant to Item 15(b) of Form 10-K.
10.1*
Settlement Agreement and General Release, dated December 20, 2013, between Occidental and Dr. Ray R. Irani (filed as Exhibit 99.1 to the Current Report on Form 8-K of Occidental dated December 20, 2013 (date of earliest event reported), filed December 23, 2013, File No. 1-9210).
10.2*
Employment Agreement, dated January 28, 2010, between Occidental and Stephen I. Chazen (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated January 28, 2010, File No. 1-9210).
10.3*
Amended and Restated Employment Agreement, dated October 9, 2008, between Occidental and Donald P. de Brier (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.4*
Amendment to Employment Agreement, dated February 25, 2013, between Occidental and Donald P. de Brier (filed as Exhibit 10.4 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2012, File No. 1-9210).
10.5*
Agreement with Chief Financial Officer (filed as Exhibit 10.7 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2012, File No. 1-9210).
10.6*
Retention Payment and Separation Benefits Attachment (filed as Exhibit 10.6 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2012, File No. 1-9210).
10.7*
Form of Indemnification Agreement between Occidental and each of its directors and certain executive officers (filed as Exhibit B to the Proxy Statement of Occidental for its May 21, 1987, Annual Meeting of Stockholders, File No. 1-9210).
10.8*
Occidental Petroleum Corporation Split Dollar Life Insurance Program and Related Documents (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 1994, File No. 1-9210).
10.9*
Split Dollar Life Insurance Agreement, dated January 24, 2002, by and between Occidental and Donald P. de Brier (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2002, File No. 1-9210).
____________________________
* Incorporated herein by reference
10.10*
Occidental Petroleum Insured Medical Plan, as amended and restated effective April 29, 1994, amending and restating the Occidental Petroleum Corporation Executive Medical Plan (as amended and restated effective April 1, 1993) (filed as Exhibit 10 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ending March 31, 1994, File No. 1-9210).
10.11*
Form of Occidental Petroleum Corporation Modified Deferred Compensation Plan (Effective December 31, 2006, Amended and Restated Effective November 1, 2008) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.12*
Form of Occidental Petroleum Corporation Amendment to Senior Executive Supplemental Life Insurance Plan (Effective as of January 1, 1986, Amended and Restated Effective as of January 1, 1996) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.13*
Form of Occidental Petroleum Corporation Amendment to Senior Executive Survivor Benefit Plan (Effective as of January 1, 1986, Amended and Restated Effective as of January 1, 1996) (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.14*
Form of Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective as of January 1, 2005, Amended and Restated as of November 1, 2008) (filed as Exhibit 10.7 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.15*
Amendment Number 1 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective As Of January 1, 2005, Amended And Restated As Of November 1, 2008) (filed as Exhibit 10.16 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2009, File No. 1-9210).
10.16*
Amendment Number 2 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective As Of January 1, 2005, Amended And Restated As Of November 1, 2008) (filed as Exhibit 10.17 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2009, File No. 1-9210).
10.17*
Amendment Number 3 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective As Of January 1, 2005, Amended and Restated as of November 1, 2008) (filed as Exhibit 10.18 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2011, File No. 1-9210).
10.18*
Amendment Number 4 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective As Of January 1, 2005, Amended and Restated as of November 1, 2008) (filed as Exhibit 10.19 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2011, File No. 1-9210).
10.19*
Amendment Number 5 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective as of January 1, 2005, Amended and Restated as of November 1, 2008) (filed as Exhibit 10.19 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2012, File No. 1-9210).
10.20*
Occidental Petroleum Corporation 2001 Incentive Compensation Plan (as amended through September 12, 2002) (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2002, File No. 1-9210).
10.21*
Terms and Conditions for Incentive Stock Option Award under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (July 2003 version) (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2003, File No. 1-9210).
10.22*
Terms and Conditions for Nonqualified Stock Option Award under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (July 2003 version) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2003, File No. 1-9210).
10.23*
Terms and Conditions of Stock Appreciation Rights Award under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2004, File No. 1-9210).
10.24*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan, as amended through October 13, 2010 (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated October 13, 2010 (date of earliest event reported), filed October 14, 2010, File No. 1-9210).
10.25*
Terms and Conditions of Stock Appreciation Rights Award under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as Exhibit 10.12 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2005, File No. 1-9210).
10.26*
Agreement to Amend Outstanding Option Awards, dated October 26, 2005 (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2005, File No. 1-9210).
10.27*
Terms and Conditions of Stock Appreciation Rights (SARs) under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (July 2006 version) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2006, File No. 1-9210).
10.28*
Form of Occidental Petroleum Corporation 2005 Deferred Stock Program (Restatement Effective as of November 1, 2008) (filed as Exhibit 10.8 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.29*
Occidental Petroleum Corporation Executive Incentive Compensation Plan (filed as Exhibit 10.69 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2005, File No. 1-9210).
10.30*
Description of financial counseling program (filed as Exhibit 10.50 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2003, File No. 1-9210).
10.31*
Description of group excess liability insurance program (filed as Exhibit 10.51 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2003, File No. 1-9210).
10.32*
Executive Stock Ownership Guidelines (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2005, File No. 1-9210).
10.33*
Form of Restricted Stock Award for Non-Employee Directors under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated February 16, 2006 (date of earliest event reported), filed February 22, 2006, File No. 1-9210).
10.34*
Amendment to Form of Restricted Stock Award for Non-Employee Directors under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended September 30, 2007, File No. 1-9210).
____________________________
* Incorporated herein by reference
10.35*
Form of Restricted Stock Award for Non-Employee Directors under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (2007 version) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended September 30, 2007, File No. 1-9210).
10.36
Director Retainer and Attendance Fees.
10.37
Description of Automatic Grant of Directors’ Restricted Stock Awards Pursuant to the Terms of the Occidental Petroleum Corporation 2005 Long-Term Incentive Plan.
10.38*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Agreement (Cash-based, Cash-settled Award) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2008, File No. 1-9210).
10.39*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Chemical Corporation Return on Assets Incentive Award Agreement (Cash-based, Cash-settled Award) (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2008, File No. 1-9210).
10.40*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Total Shareholder Return Incentive Award Agreement (Equity-based, Equity and Cash-settled Award) (filed as Exhibit 10.2 to the Current Report on Form 8-K of Occidental dated July 15, 2009 (Date of Earliest Event Reported), File No. 1-9210).
10.41*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Chemical Corporation Return on Assets Incentive Award Agreement (Cash-based, Cash-settled Award) (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2009, File No. 1-9210).
10.42*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Agreement (Cash-based, Cash-settled Award) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2009, File No. 1-9210).
10.43*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Long-Term Incentive Award Terms and Conditions (Equity-based, Cash-settled Award) (alternate - CV) (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2009, File No. 1-9210).
10.44*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Incentive Award Terms and Conditions (filed as Exhibit 10.2 to the Current Report on Form 8-K of Occidental dated October 13, 2010 (date of earliest event reported), filed October 14, 2010, File No. 1-9210).
10.45*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Total Shareholder Return Incentive Award Terms and Conditions (Equity-based, Equity and Cash-settled Award) (filed as Exhibit 10.3 to the Current Report on Form 8-K of Occidental dated October 13, 2010 (date of earliest event reported), filed October 14, 2010, File No. 1-9210).
10.46*
Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Total Shareholder Return Incentive Award Terms and Conditions (Equity-based, Equity and Cash-settled Award) (filed as Exhibit 10.2 to the Current Report on Form 8-K of Occidental dated July 13, 2011 (date of earliest event reported), filed July 18, 2011, File No. 1-9210).
10.47*
Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Incentive Award Terms and Conditions (filed as Exhibit 10.3 to the Current Report on Form 8-K of Occidental dated July 13, 2011 (date of earliest event reported), filed July 18, 2011, File No. 1-9210).
10.48*
Form of Acknowledgement Letter (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2011, File No. 1-9210).
10.49*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Long-Term Incentive Award Terms and Conditions (Cash-Based, Cash-Settled Award) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2011, File No. 1-9210).
10.50*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Chemical Corporation Return on Assets Incentive Award Terms and Conditions (Cash-Based, Cash- Settled Award) (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2011, File No. 1-9210).
10.51*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Terms and Conditions (Cash-Based, Cash-Settled Award) (filed as Exhibit 10.7 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2011, File No. 1-9210).
10.52*
Form of Restricted Stock Award for Non-Employee Directors under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended March 31, 2012, File No. 1-9210).
10.53*
Form of Restricted Stock Unit Award for Non-Employee Directors under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended March 31, 2012, File No. 1-9210).
10.54*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Award Terms and Conditions. (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended March 31, 2012, File No. 1-9210).
10.55*
Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Total Shareholder Return Incentive Award Terms And Conditions (Equity-based and Equity-settled Award) (filed as Exhibit 10.2 to Occidental's Current Report on Form 8-K dated July 11, 2012 (date of earliest event reported), filed July 13, 2012, File No. 1-9210).
10.56*
Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Incentive Award Terms and Conditions (filed as Exhibit 10.3 to Occidental's Current Report on Form 8-K dated July 11, 2012 (date of earliest event reported), filed July 13, 2012, File No. 1-9210).
10.57*
Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Long-Term Incentive Award Terms and Conditions (Cash-Based, Equity And Cash-Settled Award) (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2012, File No. 1-9210).
10.58*
Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Chemical Corporation Return on Assets Incentive Award Terms and Conditions (Cash-Based, Cash-Settled Award) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2012, File No. 1-9210).
____________________________
* Incorporated herein by reference
10.59*
Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Terms and Conditions (Cash-Based, Cash-Settled Award) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2012, File No. 1-9210).
10.60*
Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Common Stock and Sign-On Bonus and Other Award Agreement (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2012, File No. 1-9210).
10.61*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Incentive Award Terms and Conditions (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated July 10, 2013 (date of earliest event reported), filed July 16, 2013, File No. 1-9210).
10.62*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Total Shareholder Return Incentive Award Terms and Conditions (Equity-Based and Equity-Settled Award) (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated July 22, 2013 (date of earliest event reported), filed July 26, 2013, File No. 1-9210).
10.63*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Incentive Award Terms and Conditions (Performance-Based) (filed as Exhibit 10.2 to the Current Report on Form 8-K of Occidental dated July 22, 2013 (date of earliest event reported), filed July 26, 2013, File No. 1-9210).
10.64*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Return on Capital Employed Incentive Award Terms and Conditions (Equity-Based, Equity-Settled Award) (filed as Exhibit 10.3 to the Current Report on Form 8-K of Occidental dated July 22, 2013 (date of earliest event reported), filed July 26, 2013, File No. 1-9210).
10.65*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Terms and Conditions (Equity-Based, Equity-Settled Award) (filed as Exhibit 10.4 to the Current Report on Form 8-K of Occidental dated July 22, 2013 (date of earliest event reported), filed July 26, 2013, File No. 1-9210).
10.66*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Terms and Conditions (Equity-Based, Equity-Settled Award) (Americas) (filed as Exhibit 10.5 to the Current Report on Form 8-K of Occidental dated July 22, 2013 (date of earliest event reported), filed July 26, 2013, File No. 1-9210).
10.67*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Terms and Conditions (Equity-Based, Equity-Settled Award) (MENA) (filed as Exhibit 10.6 to the Current Report on Form 8-K of Occidental dated July 22, 2013 (date of earliest event reported), filed July 26, 2013, File No. 1-9210).
10.68*
Occidental Petroleum Corporation Acknowledgement Letter dated April 29, 2013 (filed as Exhibit 10.8 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.69*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Incentive Award Terms and Conditions (filed as Exhibit 10.9 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.70*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Return on Capital Employed Incentive Award Terms and Conditions (Cash-Based, Cash-Settled Award) (filed as Exhibit 10.10 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.71*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Chemical Corporation Return on Assets Incentive Award Terms and Conditions (Cash-Based, Cash-Settled Award) (filed as Exhibit 10.11 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.72*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Terms and Conditions (Cash-Based, Cash-Settled Award) (filed as Exhibit 10.12 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.73*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Terms And Conditions (Cash-Based, Cash-Settled Award) (Americas) (filed as Exhibit 10.13 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.74*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Terms and Conditions (Cash-Based, Cash-Settled Award) (MENA) (filed as Exhibit 10.14 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.75*
Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Chemical Corporation Return on Assets Incentive Award Terms and Conditions (Equity-Based, Equity-Settled Award) (filed as Exhibit 10.15 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
Statement regarding computation of total enterprise ratios of earnings to fixed charges for each of the five years in the period ended December 31, 2013.
List of subsidiaries of Occidental at December 31, 2013.
23.1
Consent of Independent Registered Public Accounting Firm.
23.2
Consent of Independent Petroleum Engineers.
31.1
Certification of CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2
Certification of CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1
Certifications of CEO and CFO Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1
Ryder Scott Company Process Review of the Estimated Future Proved Reserves and Income Attributable to Certain Fee, Leasehold and Royalty Interests and Certain Economic Interests Derived Through Certain Production Sharing Contracts as of December 31, 2013.
101.INS
XBRL Instance Document.
101.SCH
XBRL Taxonomy Extension Schema Document.
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB
XBRL Taxonomy Extension Label Linkbase Document.
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document.
____________________________
* Incorporated herein by reference
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
OCCIDENTAL PETROLEUM CORPORATION
March 3, 2014
By:
/s/ Stephen I. Chazen
Stephen I. Chazen
President
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Title
Date
/s/Stephen I. Chazen
President,
March 3, 2014
Stephen I. Chazen
Chief Executive Officer and Director
/s/ Cynthia L. Walker
Executive Vice President and
March 3, 2014
Cynthia L. Walker
Chief Financial Officer
/s/ Roy Pineci
Vice President, Controller and
March 3, 2014
Roy Pineci
Principal Accounting Officer
/s/ Spencer Abraham
Director
March 3, 2014
Spencer Abraham
/s/ Howard I. Atkins
Director
March 3, 2014
Howard I. Atkins
/s/ Eugene L. Batchelder
Director
March 3, 2014
Eugene L. Batchelder
/s/ Edward P. Djerejian
Chairman of the Board of Directors
March 3, 2014
Edward P. Djerejian
/s/ John E. Feick
Director
March 3, 2014
John E. Feick
/s/ Margaret M. Foran
Director
March 3, 2014
Margaret M. Foran
/s/ Carlos M. Gutierrez
Director
March 3, 2014
Carlos M. Gutierrez
Title
Date
/s/ William R. Klesse
Director
March 3, 2014
William R. Klesse
/s/ Avedick B. Poladian
Director
March 3, 2014
Avedick B. Poladian
/s/ Elisse B. Walter
Director
March 3, 2014
Elisse B. Walter
This report was printed on recycled paper.
© 2014 Occidental Petroleum Corporation
EXHIBIT INDEX
EXHIBITS
10.36
Director Retainer and Attendance Fees.
10.37
Description of Automatic Grant of Directors’ Restricted Stock Awards Pursuant to the Terms of the Occidental Petroleum Corporation 2005 Long-Term Incentive Plan.
Statement regarding computation of total enterprise ratios of earnings to fixed charges for each of the five years in the period ended December 31, 2013.
List of subsidiaries of Occidental at December 31, 2013.
23.1
Consent of Independent Registered Public Accounting Firm.
23.2
Consent of Independent Petroleum Engineers.
31.1
Certification of CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2
Certification of CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1
Certifications of CEO and CFO Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1
Ryder Scott Company Process Review of the Estimated Future Proved Reserves and Income Attributable to Certain Fee, Leasehold and Royalty Interests and Certain Economic Interests Derived Through Certain Production Sharing Contracts as of December 31, 2013.
101.INS
XBRL Instance Document.
101.SCH
XBRL Taxonomy Extension Schema Document.
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB
XBRL Taxonomy Extension Label Linkbase Document.
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document.