MARKET RISKS, INFLATION AND OTHER
UNCERTAINTIES

Worldwide 2017 2016 2015
Average Realizations (1)
────────────────────────────────────────────────────────────────────────────
Crude oil and NGL ($ per barrel) 48.91 38.15 44.77
Natural gas ($ per thousand cubic feet) 3.04 2.25 2.95
(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 $425 million annual after-tax effect on
Upstream consolidated plus equity company earnings. 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. For any given period, the extent of actual
benefit or detriment will be dependent on the price movements of individual
types of crude oil, 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 interest rates, currency
rates and commodity prices. In addition, the Corporation uses commodity-based
contracts, including derivatives, to manage commodity price risk and for
trading purposes. 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. The Corporation believes that there are no material market or
credit risks to the Corporation's financial position, results of operations or
liquidity 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. Beginning several years ago, an extended period of
increased demand for certain services and materials resulted in higher
operating and capital costs. Since then, multiple market changes, including
lower oil prices and reduced upstream industry activity, have contributed to
lower prices for oilfield services and materials. 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, 2018, ExxonMobil adopted
the Financial Accounting Standards Board's standard, Revenue from Contracts
with Customers, as amended. The standard establishes a single revenue
recognition model for all contracts with customers, eliminates industry and
transaction specific requirements, and expands disclosure requirements. The
standard was adopted using the Modified Retrospective method, under which prior
year results are not restated, but supplemental information on the impact of
the new standard must be provided for 2018 results, if material. The standard
is not expected to have a material impact on the Corporation's financial
statements. The cumulative effect of adoption of the new standard is de
minimis.

Effective
January 1, 2018, ExxonMobil adopted the Financial Accounting Standards Board's
Update, Financial Instruments - Overall (Subtopic 825-10): Recognition and
Measurement of Financial Assets and Financial Liabilities. The standard
requires investments in equity securities other than consolidated subsidiaries
and equity method investments to be measured at fair value with changes in the
fair value recognized through net income. Companies can elect a modified
approach for equity securities that do not have a readily determinable fair
value. The standard is not expected to have a material impact on the
Corporation's financial statements.

Effective
January 1, 2018, ExxonMobil adopted the Financial Accounting Standards Board's
Update, Compensation - Retirement Benefits (Topic 715): Improving the
Presentation of Net Periodic Pension Cost and Net Periodic Postretirement
Benefit Cost. The update requires the service cost component of net benefit
costs to be reported in the same line of the income statement as other compensation
costs and the other components of net benefit costs (non-service costs) to be
presented separately from the service cost component. Additionally, only the
service cost component of net benefit costs is eligible for capitalization. The
Corporation expects to add a new line "Non-service pension and postretirement
benefit expense" to its Consolidated Statement of Income and expects to include
all of these costs in its Corporate and financing segment. This line would
reflect the non-service costs that were previously included in "Production and
manufacturing expenses" and "Selling, general and administrative expenses". The
update is not expected to have a material impact on the Corporation's financial
statements.

Effective
January 1, 2019, ExxonMobil will adopt the Financial Accounting Standards
Board's standard, Leases. The standard requires all leases with an
initial term greater than one year be recorded on the balance sheet as an asset
and a lease liability. The Corporation is gathering and evaluating data and
recently acquired a system to facilitate implementation. We are progressing an
assessment of the magnitude of the effect on the Corporation's financial
statements.

CRITICAL ACCOUNTING ESTIMATES

The Corporation's accounting and financial
reporting fairly reflect its straightforward business model involving the
extracting, refining and marketing of hydrocarbons and hydrocarbon-based
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.