MARKET RISKS, INFLATION AND OTHER
UNCERTAINTIES

Worldwide 2018 2017 2016
Average Realizations (1)
────────────────────────────────────────────────────────────────────────────
Crude oil and NGL ($ per barrel) 62.79 48.91 38.15
Natural gas ($ per thousand cubic feet) 3.87 3.04 2.25
(1)

Crude
oil, natural gas, petroleum product and chemical prices have fluctuated in
response to changing market forces. The impacts of these price fluctuations on
earnings from Upstream, Downstream and Chemical operations have varied. In the
Upstream, a $1 per barrel change in the weighted-average realized
price of oil would have approximately a $450 million annual after-tax effect on
Upstream consolidated plus equity company earnings, excluding the impact of
derivatives. Similarly, a $0.10 per thousand cubic feet change in the worldwide
average gas realization would have approximately a $165 million annual
after-tax effect on Upstream consolidated plus equity company earnings,
excluding the impact of derivatives. For any given period, the extent of actual
benefit or detriment will be dependent on the price movements of individual
types of crude oil, results of trading activities, taxes and other government
take impacts, price adjustment lags in long-term gas contracts, and crude and
gas production volumes. Accordingly, changes in benchmark prices for crude oil
and natural gas only provide broad indicators of changes in the earnings
experienced in any particular period.

In
the very competitive downstream and chemical environments, earnings are primarily
determined by margin capture rather than absolute price levels of products
sold. Refining margins are a function of the difference between what a refiner
pays for its raw materials (primarily crude oil) and the market prices for the
range of products produced. These prices in turn depend on global and regional
supply/demand balances, inventory levels, refinery operations, import/export
balances and weather.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The global
energy markets can give rise to extended periods in which market conditions are
adverse to one or more of the Corporation's businesses. Such conditions, along
with the capital-intensive nature of the industry and very long lead times
associated with many of our projects, underscore the importance of maintaining
a strong financial position. Management views the Corporation's financial
strength as a competitive advantage.

In
general, segment results are not dependent on the ability to sell and/or
purchase products to/from other segments. Instead, where such sales take place,
they are the result of efficiencies and competitive advantages of integrated
refinery/chemical complexes. Additionally, intersegment sales are at
market-based prices. The products bought and sold between segments can also be
acquired in worldwide markets that have substantial liquidity, capacity and
transportation capabilities. About 35 percent of the Corporation's intersegment
sales represent Upstream production sold to the Downstream. Other intersegment
sales include those between refineries and chemical plants related to raw
materials, feedstocks and finished products.

Although
price levels of crude oil and natural gas may rise or fall significantly over
the short to medium term due to global economic conditions, political events, decisions
by OPEC and other major government resource owners and other factors, industry
economics over the long term will continue to be driven by market supply and
demand. Accordingly, the Corporation evaluates the viability of its major investments
over a range of prices.

The
Corporation has an active asset management program in which underperforming
assets are either improved to acceptable levels or considered for divestment.
The asset management program includes a disciplined, regular review to ensure
that all assets are contributing to the Corporation's strategic objectives
resulting in an efficient capital base.

Risk Management

The
Corporation's size, strong capital structure, geographic diversity and the
complementary nature of the Upstream, Downstream and Chemical businesses reduce
the Corporation's enterprise-wide risk from changes in commodity prices,
currency rates and interest rates. In addition, the Corporation uses
commodity-based contracts, including derivatives, to manage commodity price
risk and for trading purposes. The Corporation's commodity derivatives are not
accounted for under hedge accounting. At times, the Corporation also enters
into forward currency and interest rate derivatives, none of which are material
to the Corporation's financial position as of December 31, 2018 and 2017, or
results of operations for the years ended 2018, 2017 and 2016. Credit risk associated
with the Corporation's derivative position is mitigated by several factors,
including the use of derivative clearing exchanges and the quality of and
financial limits placed on derivative counterparties. No material market or
credit risks to the Corporation's financial position, results of operations or
liquidity exist as a result of the derivatives described in Note 13. The
Corporation maintains a system of controls that includes the authorization,
reporting and monitoring of derivative activity.

The
Corporation is exposed to changes in interest rates, primarily on its
short-term debt and the portion of long-term debt that carries floating
interest rates. The impact of a 100-basis-point change in interest rates
affecting the Corporation's debt would not be material to earnings, cash flow
or fair value. The Corporation has access to significant capacity of long-term
and short-term liquidity. Internally generated funds are expected to cover the
majority of financial requirements, supplemented by long-term and short-term
debt. Some joint-venture partners are dependent on the credit markets, and
their funding ability may impact the development pace of joint-venture
projects.

The
Corporation conducts business in many foreign currencies and is subject to
exchange rate risk on cash flows related to sales, expenses, financing and
investment transactions. Fluctuations in exchange rates are often offsetting
and the impacts on ExxonMobil's geographically and functionally diverse
operations are varied. The Corporation makes limited use of currency exchange
contracts to mitigate the impact of changes in currency values, and exposures
related to the Corporation's limited use of the currency exchange contracts are
not material.

Inflation and Other Uncertainties

The
general rate of inflation in many major countries of operation has remained
moderate over the past few years, and the associated impact on non-energy costs
has generally been mitigated by cost reductions from efficiency and
productivity improvements. Prices for services and materials continue to evolve
in response to constant changes in commodity markets and industry activities,
impacting operating and capital costs. The Corporation monitors market trends
and works to minimize costs in all commodity price environments through its
economies of scale in global procurement and its efficient project management
practices.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

RECENTLY ISSUED ACCOUNTING STANDARDS

Effective January 1, 2019, the Corporationadoptedthe Financial Accounting Standards Board's Standard, Leases
(Topic 842), as amended. The standard requires all leases to be recorded on
the balance sheet as a right of use asset and a lease liability. The
Corporation useda transition method that applies the new
lease standard at January 1, 2019, and recognizes any cumulative-effect
adjustments to the opening balance of 2019 retained earnings. The Corporation
applied a policy election to exclude short-term leases from balance sheet
recognition and also elected certain practical expedients at adoption. As
permitted under these expedients the Corporation did not reassess whether existing
contracts are or contain leases, the lease classification for any existing
leases, initial direct costs for any existing lease and whether existing land
easements and rights of way, that were not previously accounted for as leases,
are or contain a lease. At January 1, 2019, the operating lease liability is
estimated to be in the range of $3.3billion and the operating
lease right of use asset is estimated to be in the range of $4.3billion, including about $1.0billion related to prepaid
leases. The cumulative effect adjustment is expected to be de minimis.

CRITICAL ACCOUNTING ESTIMATES

The
Corporation's accounting and financial reporting fairly reflect its integrated
business model involving exploration for, and production of, crude oil and
natural gas and manufacture, trade, transport and sale of crude oil, natural
gas, petroleum products, petrochemicals and a wide variety of specialty products.
The preparation of financial statements in conformity with U.S. Generally
Accepted Accounting Principles (GAAP) requires management to make estimates and
judgments that affect the reported amounts of assets, liabilities, revenues and
expenses and the disclosure of contingent assets and liabilities. The
Corporation's accounting policies are summarized in Note 1.

Oil and Natural Gas Reserves

The
estimation of proved reserves is an ongoing process based on rigorous technical
evaluations, commercial and market assessments and detailed analysis of well
information such as flow rates and reservoir pressure declines, among other
factors. The estimation of proved reserves is controlled by the Corporation
through long-standing approval guidelines. Reserve changes are made within a
well-established, disciplined process driven by senior level geoscience and
engineering professionals, assisted by the Global Reserves group which has
significant technical experience, culminating in reviews with and approval by
senior management. Notably, the Corporation does not use specific quantitative
reserve targets to determine compensation. Key features of the reserve
estimation process are covered in Disclosure of Reserves in Item 2.

Oil
and natural gas reserves include both proved and unproved reserves.

·Proved oil and natural
gas reserves are determined in accordance with Securities and Exchange
Commission (SEC) requirements. Proved reserves are those quantities of oil and
natural gas which, by analysis of geoscience and engineering data, can be
estimated with reasonable certainty to be economically producible under
existing economic and operating conditions and government regulations. Proved
reserves are determined using the average of first-of-month oil and natural gas
prices during the reporting year.

Proved
reserves can be further subdivided into developed and undeveloped reserves.
Proved developed reserves include amounts which are expected to be recovered
through existing wells with existing equipment and operating methods. Proved
undeveloped reserves include amounts expected to be recovered from new wells on
undrilled proved acreage or from existing wells where a relatively major
expenditure is required for completion. Proved undeveloped reserves are
recognized only if a development plan has been adopted indicating that the
reserves are scheduled to be drilled within five years, unless specific
circumstances support a longer period of time.

The
percentage of proved developed reserves was 68 percent of total proved reserves
at year-end 2018 (including both consolidated and equity company reserves), an
increase from 66 percent in 2017, and has been over 60 percent for the last ten
years. Although the Corporation is reasonably certain that proved reserves will
be produced, the timing and amount recovered can be affected by a number of
factors including completion of development projects, reservoir performance,
regulatory approvals, government policy, consumer preferences and significant
changes in long-term oil and natural gas prices.

·Unproved reserves are quantities
of oil and natural gas with less than reasonable certainty of recoverability
and include probable reserves. Probable reserves are reserves that, together
with proved reserves, are as likely as not to be recovered.

Revisions in previously
estimated volumes of proved reserves for existing fields can occur due to the
evaluation or re-evaluation of (1) already available geologic, reservoir
or production data, (2) new geologic, reservoir or production data or
(3) changes in the average of first-of-month oil and natural gas prices
and / or costs that are used in the estimation of reserves. Revisions can also
result from significant changes in development strategy or production equipment
and facility capacity.