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## OMNICOM GROUP INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Variable Consideration. Some of our client arrangements include variable consideration provisions, which include performance incentives, tiered commission structures and vendor rebates in certain markets outside of the United States. Variable consideration is estimated and included in total consideration at contract inception based on either the expected value method or the most likely outcome method. These estimates are based on historical award experience, anticipated performance and other factors known at the time. Performance incentives are typically recognized in revenue over time. Variable consideration for our media businesses in certain international markets includes rebate revenue and is recognized when it is probable that the media will be run, including when it is not subject to cancellation by the client. In addition, when we receive rebates or credits from vendors for transactions entered into on behalf of clients, they are remitted to the clients in accordance with contractual requirements or retained by us based on the terms of the client contract or local law. Amounts passed on to clients are recorded as a liability and amounts retained by us are recorded as revenue when earned, typically when the media is run.
Operating Expenses. Operating expenses include cost of services, selling, general and administrative expenses, or SG&A, and depreciation and amortization. We measure cost of services in two distinct categories: salary and service costs and occupancy and other costs. As a service business, salary and service costs make up the vast majority of our operating expenses and substantially all these costs comprise the essential components directly linked to the delivery of our services. Salary and service costs include employee compensation and benefits, freelance labor and direct service costs, which include third-party supplier costs and client-related travel costs. Occupancy and other costs consist of the indirect costs related to the delivery of our services, including office rent and other occupancy costs, equipment rent, technology costs, general office expenses and other expenses. SG&A expenses primarily consist of third-party marketing costs, professional fees and compensation and benefits and occupancy and other costs of our corporate and executive offices, which includes group-wide finance and accounting, treasury, legal and governance, human resource oversight and similar costs.
Cash and Cash Equivalents. Cash and cash equivalents include cash in banks and highly liquid interest-bearing time deposits with original maturities of three months or less. Due to the short-term nature of these investments, carrying value approximates fair value. We have a policy governing counterparty credit risk for financial institutions that hold our cash and cash equivalents and we have deposit limits for each institution.
Short-Term Investments. Short-term investments include interest-bearing time deposits with maturities of less than twelve months. Short-term investments are carried at cost, which approximates fair value.
Work in Process. Work in process represents accrued costs incurred on behalf of customers, including media and production costs, and fees and other third-party costs that have not yet been billed. Media and production costs are billed during the production process in accordance with the terms of the client contract. Substantially all unbilled fees and costs will be billed within the next 30 days.
Property and Equipment. Property and equipment are carried at cost and are depreciated over the estimated useful lives of the assets using the straight-line method. The estimated useful lives range from seven to ten years for furniture and three to five years for equipment. Leasehold improvements are amortized on a straight-line basis over the shorter of the lease term or the estimated useful life of the asset. Assets under finance leases are amortized on a straight-line basis over the lease term.
Equity Method Investments. Investments in companies where we exercise significant influence over the operating and financial policies of the investee and own less than 50% of the equity are accounted for using the equity method. Our proportionate share of the net income or loss of equity method investments is included in results of operations and any dividends received reduce the carrying value of the investment. The excess of the cost of our investment over our proportionate share of the fair value of the net assets of the investee at the acquisition date is recognized as goodwill and included in the carrying amount of the investment. Goodwill in the equity method investments is not amortized. Gains and losses from changes in our ownership interests are recorded in results of operations until control is achieved. In circumstances where a change in our ownership interest results in obtaining control, the existing carrying value of the investment is remeasured to the acquisition date fair value and any gain or loss is recognized in results of operations. We periodically review the carrying value of the equity method investments to determine if there has been an other-than-temporary decline in carrying value. A variety of factors are considered when determining if a decline in carrying value is other-than- temporary, including the financial condition and business prospects of the investee, as well as our investment intent.
Marketable Equity Securities. Marketable equity securities are measured at fair value and changes in fair value are recognized in results of operations.
Non-Marketable Equity Securities . Non-marketable equity securities do not have a readily determinable fair value and are measured at cost, less any impairment, and are adjusted for observable changes in fair value from transactions for identical or similar securities of the same issuer.
Goodwill and Intangible Assets. Goodwill represents the excess of the acquisition cost over the fair value of the net assets acquired. Goodwill is not amortized but is periodically reviewed for impairment. Intangible assets comprise customer relationships, including the related customer contracts and trade names, and purchased and internally developed software and are
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## Contract assets and liabilities
## OMNICOM GROUP INC. AND SUBSIDIARIES
## NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Work in process includes contract assets, unbilled fees and costs, and media and production costs. Contract liabilities primarily consist of customer advances. Work in process and contract liabilities were (in millions):
<img src='content_image/1044408.jpg'>
Work in process represents accrued costs incurred on behalf of customers, including media and production costs, and fees and other third-party costs that have not yet been billed. Media and production costs are billed during the production process in accordance with the terms of the client contract. Contract assets primarily include incentive fees, which are not material and will be billed to clients in accordance with the terms of the client contract. Substantially all unbilled fees and costs will be billed within the next 30 days. The contract liability primarily represents advance billings to customers in accordance with the terms of the client contracts, primarily for the reimbursement of third-party costs that are generally incurred in the near term. No impairment losses to the contract assets were recorded in 2020 and 2019.
## 4. Net Income per Share
The computations of basic and diluted net income per share were (in millions, except per share amounts):
<img src='content_image/1044409.jpg'>
## 5. Business Combinations
Acquisitions completed in 2020 increased goodwill $82.4 million. In addition, during 2020, we acquired additional equity interests in certain majority owned subsidiaries, which are accounted for as equity transactions, and no additional goodwill was recorded. None of the acquisitions in 2020, either individually or in the aggregate, was material to our results of operations or financial position.
The evaluation of potential acquisitions is based on various factors, including specialized know-how, reputation, geographic coverage, competitive position and service offerings, as well as our experience and judgment. Our acquisition strategy is focused on acquiring the expertise of an assembled workforce in order to continue to build upon the core capabilities of our strategic business platforms and agency brands, through the expansion of their geographic area or their service capabilities to better serve our clients. Certain acquisitions include an initial payment at closing and provide for future additional contingent purchase price payments (earn-outs), which are derived using the performance of the acquired company and are based on predetermined formulas. At December 31, 2020 and 2019, contingent purchase price obligations were $71.9 million and $107.7 million, respectively, of which $32.1 million and $29.5 million, respectively, are included in other current liabilities.
For each acquisition, we undertake a detailed review to identify other intangible assets that are required to be valued separately. We use several market participant measurements to determine fair value. This approach includes consideration of similar and recent transactions, as well as utilizing discounted expected cash flow methodologies, and when available and as appropriate, we use comparative market multiples to supplement our analysis. As is typical for most service businesses, a substantial portion of the intangible asset value we acquire is the specialized know-how of the workforce, which is treated as part
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## 11. Income Taxes
The components of income before income taxes were (in millions):
## OMNICOM GROUP INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<img src='content_image/1039643.jpg'>
Income tax expense (benefit) was (in millions):
<img src='content_image/1039644.jpg'>
The reconciliation from the statutory U.S. federal income tax rate to our effective tax rate is:
<img src='content_image/1039645.jpg'>
Our effective tax rate for 2020 increased year-over-year to 27.1% from 26.0%. The non-deductibility in certain jurisdictions of a portion of the COVID-19 repositioning costs recorded in the second quarter of 2020 had the effect of increasing our effective tax rate for 2020. This increase was substantially offset by a lower effective tax rate on our foreign earnings resulting from a change in legislation. The effective tax rate for 2019 includes a reduction of $10.8 million primarily from the net favorable settlement of uncertain tax positions in various jurisdictions in the second quarter of 2019. The international tax rate differentials in 2020 and 2019 are primarily attributed to our earnings in Germany, Australia, France, Japan and Brazil being taxed at higher rates than the U.S. statutory tax rate.
The Tax Cuts and Jobs Act of 2017, or Tax Act, among other things, implemented a territorial tax system and imposed a one-time transition tax on the deemed repatriation of accumulated earnings of foreign subsidiaries. At December 31, 2020 and 2019, the transition tax liability was $112.0 million and $123.6 million, respectively. The territorial tax system allows us to repatriate earnings of our foreign subsidiaries without incurring additional U.S. tax by providing a 100% dividend exemption. While a territorial tax system limits U.S. federal income tax to domestic source income, foreign source income is subject to tax in the appropriate foreign jurisdiction at the local rate, which in certain jurisdictions may be higher than the U.S. federal statutory income tax rate of 21%. As a result, the foreign tax rate differential will cause our effective tax rate to be higher than the U.S. federal statutory income tax rate.
We have elected to account for any tax on the global intangible low-taxed income, or GILTI, in the period in which it is incurred. In 2020 and 2019, we provided $3.0 million and $14.7 million, respectively, for tax impacts of GILTI.
Income tax expense in 2020, 2019 and 2018 includes $3.8 million, $2.2 million and $3.6 million, respectively, of interest, net of tax benefit, and penalties related to tax positions taken on our tax returns. At December 31, 2020 and 2019, accrued interest and penalties were $23.5 million and $20.0 million, respectively.
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financial position. A contraction in the availability of credit may make it more difficult for us to meet our working capital requirements. In addition, a disruption in the credit markets could adversely affect our clients and could cause them to delay payment for our services or take other actions that would negatively affect our working capital. In such circumstances, we may need to obtain additional financing to fund our day-to-day working capital requirements, which may not be available on favorable terms, or at all. Even if we take action to respond to adverse economic conditions, reductions in revenue and disruptions in the credit markets by aligning our cost structure and more efficiently managing our working capital, such actions may not be effective.
In an economic downturn, the risk of a material loss related to media purchases and production costs incurred on behalf of our clients could significantly increase, and methods for managing or mitigating such risk may be less available or unavailable.
In the normal course of business, our agencies enter into contractual commitments with media providers and production companies on behalf of our clients at levels that can substantially exceed the revenue from our services. These commitments are included in accounts payable when the services are delivered by the media providers or production companies. If permitted by local law and the client agreement, many of our agencies purchase media and production services for our clients as an agent for a disclosed principal. In addition, while operating practices vary by country, media type and media vendor, in the United States and certain foreign markets, many of our agencies’ contracts with media and production providers specify that our agencies are not liable to the media and production providers under the theory of sequential liability until and to the extent we have been paid by our client for the media or production services.
Where purchases of media and production services are made by our agencies as a principal or are not subject to the theory of sequential liability, the risk of a material loss as a result of payment default by our clients could increase significantly and such a loss could have a material adverse effect on our business, results of operations and financial position.
In addition, our methods of managing the risk of payment default, including obtaining credit insurance, requiring payment in advance, mitigating the potential loss in the marketplace or negotiating with media providers, may be less available or unavailable during a severe economic downturn.
## Business and Operational Risks
Clients periodically review and change their advertising, marketing and corporate communications requirements and relationships. If we are unable to remain competitive or retain key clients, our business, results of operations and financial position may be adversely affected.
We operate in a highly competitive industry. Key competitive considerations for retaining existing clients and winning new clients include our ability to develop solutions that meet client needs in a rapidly changing environment, the quality and effectiveness of our services and our ability to serve clients efficiently, particularly large multinational clients, on a broad geographic basis. While many of our client relationships are long-standing, from time to time clients put their advertising, marketing and corporate communications business up for competitive review. We have won and lost accounts as a result of these reviews. To the extent that we are not able to remain competitive or retain key clients, our revenue may be adversely affected, which could have a material adverse effect on our business, results of operations and financial position.
Acquiring new clients and retaining existing clients depends on our ability to avoid and manage conflicts of interest arising from other client relationships, retaining key personnel and maintaining a highly skilled workforce.
Our ability to acquire new clients and retain existing clients may, in some cases, be limited by clients’ perceptions of, or policies concerning, conflicts of interest arising from other client relationships. If we are unable to maintain multiple agencies to manage multiple client relationships and avoid potential conflicts of interests, our business, results of operations and financial position may be adversely affected.
As a service business, our ability to attract and retain key personnel is an important aspect of our competitiveness. If we are unable to attract and retain key personnel, our ability to provide our services in the manner clients have come to expect may be adversely affected, which could harm our reputation and result in a loss of clients, which could have a material adverse effect on our business, results of operations and financial position.
The loss of several of our largest clients could have a material adverse effect on our business, results of operations and financial position.
In 2020, our 100 largest clients represented approximately 54% of our revenue. Clients generally are able to reduce or cancel current or future spending on advertising, marketing and corporate communications projects at any time on short notice for any reason. A significant reduction in spending on our services by our largest clients, or the loss of several of our largest clients, if not replaced by new clients or an increase in business from existing clients, would adversely affect our revenue and could have a material adverse effect on our business, results of operations and financial position.
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The change in benefit obligation and fair value of plan assets of the defined benefit pension plans were (in millions):
<img src='content_image/1044744.jpg'>
The funded status and balance sheet classification of the defined benefit pension plans were (in millions):
<img src='content_image/1044743.jpg'>
At December 31, 2020 and 2019, the accumulated benefit obligation for our defined benefit pension plans was $243.9 million and $268.9 million, respectively.
Plans with benefit obligations in excess of plan assets were (in millions):
<img src='content_image/1044742.jpg'>
The weighted average assumptions used to determine the benefit obligation were:
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At December 31, 2020, the maturities of the lease liabilities were (in millions):
## OMNICOM GROUP INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<img src='content_image/1059468.jpg'>
## 17. Temporary Equity - Redeemable Noncontrolling Interests
Owners of noncontrolling equity interests in some of our subsidiaries have the right in certain circumstances to require us to purchase all or a portion of their equity interest at fair value as defined in the applicable agreements. Assuming that the subsidiaries perform over the relevant periods at their current profit levels, at December 31, 2020 the aggregate estimated maximum amount we could be required to pay in future periods is $209.7 million, of which $151.0 million is currently exercisable by the holders. If these rights are exercised, there would be an increase in net income attributable to Omnicom as a result of our increased ownership interest and the reduction of net income attributable to noncontrolling interests. The ultimate amount paid could be significantly different because the redemption amount depends on the future results of operations of the subject businesses, the timing of the exercise of these rights and changes in foreign currency exchange rates.
## 18. Commitments and Contingent Liabilities
In the ordinary course of business, we are involved in various legal proceedings. We do not expect that these proceedings will have a material adverse effect on our results of operations or financial position.
## 19. Accumulated Other Comprehensive Income
Changes in accumulated other comprehensive income (loss), net of income taxes were (in millions):
<img src='content_image/1059469.jpg'>
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## OMNICOM GROUP INC. AND SUBSIDIARIES
## NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The estimated fair value of the foreign currency and interest rate derivative instruments is determined using model-derived valuations, taking into consideration foreign currency rates for the foreign currency derivatives and readily observable inputs for LIBOR interest rates and yield curves to derive the present value of the future cash flows for the interest rate derivatives and counterparty credit risk for each. The estimated fair value of the contingent purchase price obligations is calculated in accordance with the terms of each acquisition agreement and is discounted. The fair value of long-term debt is based on quoted market prices.
## 21. Derivative Instruments and Hedging Activities
We manage our exposure to foreign currency exchange rate risk and interest rate risk through various strategies, including the use of derivative financial instruments. We use forward foreign exchange contracts as economic hedges to manage the cash flow volatility arising from foreign currency exchange rate fluctuations. We may use interest rate swaps to manage our interest expense and structure our long-term debt portfolio to achieve a mix of fixed rate and floating rate debt. We do not use derivatives for trading or speculative purposes. Using derivatives exposes us to the risk that counterparties to the derivative contracts will fail to meet their contractual obligations. We manage that risk through careful selection and ongoing evaluation of the counterparty financial institutions based on specific minimum credit standards and other factors.
We evaluate the effects of changes in foreign currency exchange rates, interest rates and other relevant market risks on our derivatives. We periodically determine the potential loss from market risk on our derivatives by performing a value-at-risk analysis, or VaR. VaR is a statistical model that uses historical currency exchange rate data to measure the potential impact on future earnings of our derivative financial instruments assuming normal market conditions. The VaR model is not intended to represent actual losses but is used as a risk estimation and management tool. Based on the results of the model, we estimate with 95% confidence a maximum one-day change in the net fair value of our derivative financial instruments at December 31, 2020 was not significant.
## Foreign Currency Exchange Risk
As an integral part of our global treasury operations, we centralize our cash and use notional multicurrency pools to manage the foreign currency exchange risk that arises from imbalances between subsidiaries and their respective treasury centers. In addition, there are circumstances where revenue and expense transactions are not denominated in the same currency. In these instances, amounts are either promptly settled or hedged with forward foreign exchange contracts. To manage this risk, we had outstanding forward foreign exchange contracts with an aggregate notional amount of $169.6 million and $284.2 million at December 31, 2020 and 2019, respectively.
Foreign currency derivatives are designated as fair value hedges; therefore, any gain or loss in fair value incurred on those instruments is recorded in results of operations and is generally offset by decreases or increases in the fair value of the underlying exposure. By using these financial instruments, we reduce financial risk of adverse foreign exchange changes by foregoing any gain which might occur if the markets move favorably. The terms of our forward foreign exchange contracts are generally less than 90 days.
## 22. New Accounting Standards
In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740) or ASU 2019-12, which, among other things, amends the rules for recognizing deferred taxes for investments, performing intra-period tax allocations and calculating income taxes in interim periods and reduces complexity in certain areas, including the accounting for transactions that result in a step-up in the tax basis of goodwill and allocating taxes to members of a consolidated group. ASU 2019-12 is effective January 1, 2021. We do not expect the adoption of ASU 2019-12 will have a material effect on our results of operations and financial position.
## 23. Subsequent Events
We have evaluated events subsequent to the balance sheet date and determined there have not been any events that have occurred that would require adjustment to or disclosure in the consolidated financial statements.
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## We rely extensively on information technology systems, and cybersecurity incidents could adversely affect us.
We rely on information technology systems and infrastructure to process, store and transmit data, summarize results, manage our business and maintain client advertising and marketing information. Increased cybersecurity threats and attacks, which are constantly evolving, pose a risk to our systems and networks. For example, in February 2021, we experienced a cybersecurity incident that resulted in the disruption of certain of our information technology systems at one of our networks. Based on the information currently known and our investigation to date, we do not believe the incident will have a material impact on our business, operations or financial results. However, cybersecurity threats and attacks in the future could be material. Security breaches, improper use of our systems and unauthorized access to our data and information by employees and others may pose a risk that sensitive data may be exposed to unauthorized persons or to the public. We also have access to sensitive or personal data or information that is subject to privacy laws and regulations. Our systems and processes to protect against, detect, prevent, respond to and mitigate cybersecurity incidents and our organizational training for employees to develop an understanding of cybersecurity risks and threats may be unable to prevent material security breaches, theft, modification or loss of data, employee malfeasance and additional known and unknown threats. Such events could adversely affect our business and reputation. We also use third-party service providers, including cloud providers, to store, transmit and process data. These third-party service providers could also be subject to cybersecurity incidents that could adversely affect us.
In addition, in 2020 and continuing into 2021, the overwhelming majority of our workforce temporarily transitioned to working from home during the COVID-19 pandemic. The increase in the number of our employees working from home may increase certain business and procedural control risks, including increased risk of cybersecurity incidents and exposure of sensitive business and client advertising and marketing information as well as personal data or information.
## Risks Related to International Operations
## Currency exchange rate fluctuations have impacted, and in the future could impact our business, results of operations and financial position.
In 2020, our international operations represented approximately 45% of our revenue. We operate in all major international markets including the Euro Zone, the United Kingdom, or the U.K., Australia, Brazil, Canada, China and Japan. Our agencies transact business in more than 50 different currencies. Substantially all of our foreign operations transact business in their local currency, and accordingly their financial statements are translated into U.S. Dollars. As a result, both adverse and beneficial fluctuations in foreign exchange rates impact our business, results of operations and financial position. In addition, funds transferred to the United States can be adversely or beneficially impacted by changes in foreign currency exchange rates.
## As a global business we face certain risks of doing business internationally, and we are exposed to risks from operating in high- growth markets and developing countries, which could have a material adverse effect on our business, results of operations and financial position.
The operational and financial performance of our international businesses are affected by global and regional economic conditions, competition for new business and staff, currency exchange rate fluctuations, political conditions, differing regulatory environments and other risks associated with extensive international operations. In addition, we conduct business in numerous high-growth markets and developing countries that tend to have longer billing collection cycles, currency repatriation restrictions and commercial laws that can be undeveloped, vague, inconsistently enforced, retroactively applied or frequently changed. The risks associated with our international operations could have a material adverse effect on our business, results of operations and financial position. Additionally, our operations are subject to the United States Foreign Corrupt Practices Act and other anti-corruption and anti-bribery laws and regulations. These laws and regulations are complex and stringent, and any violation could have an adverse effect on our business and reputation. For financial information by geographic region, see Note 8 to the consolidated financial statements.
We have substantial operations in the U.K. and the Euro Zone. On December 31, 2020, the U.K. completed its separation from the European Union, or E.U., (commonly referred to as “Brexit”) and entered into an agreement, or Brexit Agreement, with the E.U. that defines the terms of their relationship, covering, among other things, trade and tariffs, services and travel. The uncertainties related to the impact of the Brexit Agreement have cross-border operational, financial and tax implications, among others, and any economic volatility that may arise in the U.K., the E.U. or elsewhere may adversely affect our business.
## Risks Related to Acquisitions
## We may be unsuccessful in evaluating material risks involved in completed and future acquisitions.
We regularly evaluate potential acquisitions of businesses that are complementary to our businesses and client needs. As part of the process, we conduct business, legal and financial due diligence to identify and evaluate material risks involved in any particular transaction. Despite our efforts, we may be unsuccessful in ascertaining or evaluating all such risks. As a result, the intended advantages of any given acquisition may not be realized. If we fail to identify certain material risks from one or more acquisitions, our business, results of operations and financial position could be adversely affected.
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## Our goodwill is an intangible asset that may become impaired, which could have a material adverse effect on our business, results of operations and financial position.
In accordance with generally accepted accounting principles in the United States, or U.S. GAAP or GAAP, we have recorded a significant amount of goodwill related to our acquisitions; a substantial portion of which represents the intangible specialized know-how of the acquired workforce. As discussed in Note 2 to the consolidated financial statements, we review the carrying value of goodwill for impairment annually at June 30 and whenever events or circumstances indicate the carrying value may not be recoverable. The estimates and assumptions about future results of operations and cash flows made in connection with the impairment testing could differ from future actual results of operations and cash flows. While we have concluded, for each year presented in the financial statements included in this report, that our goodwill is not impaired, future events could cause us to conclude that the intangible asset values associated with a given operation may become impaired. Any resulting non-cash impairment charge could have a material adverse effect on our business, results of operations and financial position.
## Regulatory Risks
## Government regulation and consumer advocates may limit the scope and content of our services, which could affect our ability to meet our clients’ needs, which could have a material adverse effect on our business, results of operations and financial position.
Government agencies and consumer groups directly or indirectly affect or attempt to affect the scope, content and manner of presentation of advertising, marketing and corporate communications services, through regulation or other governmental action, which could affect our ability to meet our clients’ needs. Such regulation may seek, among other things, to limit the tax deductibility of advertising expenditures by certain industries or for certain products and services. In addition, there has been a tendency on the part of businesses to resort to the judicial system to challenge advertising practices and claims, which could cause our clients affected by such actions to reduce their spending on our services. Any regulatory or judicial action that affects our ability to meet our clients' needs or reduces client spending on our services could have a material adverse effect on our business, results of operations and financial position.
Further, laws and regulations related to user privacy, use of personal information and Internet tracking technologies have been proposed or enacted in the United States and a number of international markets. These laws and regulations could affect the acceptance of new communications technologies and the use of current communications technologies as advertising media. These actions could affect our business and reduce demand for certain of our services, which could have a material adverse effect on our business, results of operations and financial position.
## We could be affected by future laws or regulations enacted in response to climate change concerns and other actions.
Our businesses could be indirectly affected by increased prices for goods or services provided to us by companies that are directly affected by laws and regulations aimed at mitigating the impact of climate change. Specifically, these companies may seek to pass their increased costs through to their customers. Further, if our clients are impacted by such laws or requirements, either directly or indirectly, their spending for advertising and marketing services may decline, which could adversely impact our business, results of operations and financial position. Additionally, to comply with potential future changes in environmental laws and regulations, we may need to incur additional costs; therefore, at this time, we cannot estimate what impact such regulations may have on our business, results of operations and financial position.
## Item 1B. Unresolved Staff Comments
None.
## Item 2. Properties
We conduct business and maintain offices throughout the world. The facility requirements of our businesses are similar across geographic regions and disciplines. Substantially all our office space is leased under operating leases with varying expiration dates. Lease obligations of our foreign operations are generally denominated in their local currency. We believe that our facilities are adequate for our current operations and are well maintained. Our principal corporate offices are located at 280 Park Avenue, New York, New York; 1055 Washington Boulevard, Stamford, Connecticut and 525 Okeechobee Boulevard, West Palm Beach, Florida. We also maintain executive offices in London, England; Shanghai, China and Singapore.
Notes 2 and 16 to the consolidated financial statements provide a description of our lease expense, which comprises a significant component of our occupancy and other costs, and our lease commitments.
## Item 3. Legal Proceedings
In the ordinary course of business, we are involved in various legal proceedings. We do not expect that these proceedings will have a material adverse effect on our results of operations or financial position.
## Item 4. Mine Safety Disclosures
Not Applicable.
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As of February 7, 2019, the following number of exchangeable shares was outstanding for Molson Coors Canada, Inc.:
Class A Exchangeable Shares—2,757,201 shares
Class B Exchangeable Shares—14,807,311 shares
The Class A exchangeable shares and Class B exchangeable shares are shares of the share capital in Molson Coors Canada Inc., a wholly-owned subsidiary of the registrant. They are publicly traded on the Toronto Stock Exchange under the symbols TPX.A and TPX.B, respectively. These shares are intended to provide substantially the same economic and voting rights as the corresponding class of Molson Coors common stock in which they may be exchanged. In addition to the registered Class A common stock and the Class B common stock, the registrant has also issued and outstanding one share each of a Special Class A voting stock and Special Class B voting stock. The Special Class A voting stock and the Special Class B voting stock provide the mechanism for holders of Class A exchangeable shares and Class B exchangeable shares to be provided instructions to vote with the holders of the Class A common stock and the Class B common stock, respectively. The holders of the Special Class A voting stock and Special Class B voting stock are entitled to one vote for each outstanding Class A exchangeable share and Class B exchangeable share, respectively, excluding shares held by the registrant or its subsidiaries, and generally vote together with the Class A common stock and Class B common stock, respectively, on all matters on which the Class A common stock and Class B common stock are entitled to vote. The Special Class A voting stock and Special Class B voting stock are subject to a voting trust arrangement. The trustee which holds the Special Class A voting stock and the Special Class B voting stock is required to cast a number of votes equal to the number of then-outstanding Class A exchangeable shares and Class B exchangeable shares, respectively, but will only cast a number of votes equal to the number of Class A exchangeable shares and Class B exchangeable shares as to which it has received voting instructions from the owners of record of those Class A exchangeable shares and Class B exchangeable shares, other than the registrant or its subsidiaries, respectively, on the record date, and will cast the votes in accordance with such instructions so received.
Documents Incorporated by Reference: Portions of the registrant's definitive proxy statement for the registrant's 2019 annual meeting of stockholders, which will be filed no later than 120 days after the close of the registrant's fiscal year ended December 31, 2018, are incorporated by reference under Part III of this Annual Report on Form 10-K.
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(2) During the fourth quarter of 2016, we recorded a charge of approximately $50 million within excise taxes due to assessments received from a local country regulatory authority in Europe related to indirect tax calculations. See Note 18, "Commitments and Contingencies" for further discussion.
The following table presents total assets and select cash flow information by segment:
<img src='content_image/1053356.jpg'>
(1) For the year ended December 31, 2016, represents MillerCoors' activity for the post-Acquisition period of October 11, 2016, through December 31, 2016.
The following table presents net sales by geography, based on the location of the customer:
<img src='content_image/1053359.jpg'>
(1) Prior to October 11, 2016, MCBC’s 42% share of MillerCoors' results of operations was reported as equity income in MillerCoors in the consolidated statements of operations. As a result of the completion of the Acquisition, beginning October 11, 2016, MillerCoors' results of operations were fully consolidated into MCBC’s consolidated financial statements and included in the U.S. segment. Net sales from the period October 11, 2016, through December 31, 2016, reflect the consolidation of MillerCoors in the U.S. segment.
(2) Reflects net sales from the individual countries within our Central European operations (included in our Europe segment), as well as our International segment, for which no individual country has total net sales exceeding 10% of the total consolidated net sales.
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The following represents our proportionate share in net income attributable to MillerCoors reported under the equity method of accounting prior to the Acquisition:
<img src='content_image/1045975.jpg'>
(1) The net adjustment is to eliminate all share-based compensation impacts related to pre-existing SABMiller equity awards held by former Miller Brewing Company employees employed by MillerCoors, as well as to add back all share-based compensation impacts related to pre- existing MCBC equity awards held by former MCBC employees who transferred to MillerCoors.
(2) Represents a benefit associated with an anticipated refund to CBC of U.S. federal excise tax paid on products imported by CBC based on qualifying volumes exported by CBC from the U.S. The anticipated refund is recorded within other non-current assets on the consolidated balance sheet as of December 31, 2018.
## Investments
Our investments include both equity method and consolidated investments. Those entities identified as VIEs have been evaluated to determine whether we are the primary beneficiary. The VIEs included under "Consolidated VIEs" below are those for which we have concluded that we are the primary beneficiary and accordingly, consolidate these entities. None of our consolidated VIEs held debt as of December 31, 2018, or December 31, 2017. We have not provided any financial support to any of our VIEs during 2018 that we were not previously contractually obligated to provide. Amounts due to and due from our equity method investments are recorded as affiliate accounts payable and affiliate accounts receivable. See below under "Affiliate Transactions" for further details.
Authoritative guidance related to the consolidation of VIEs requires that we continually reassess whether we are the primary beneficiary of VIEs in which we have an interest. As such, the conclusion regarding the primary beneficiary status is subject to change and we continually evaluate circumstances that could require consolidation or deconsolidation. As of December 31, 2018, and December 31, 2017, our consolidated VIEs are Cobra Beer Partnership, Ltd. ("Cobra U.K."), Grolsch U.K. Ltd ("Grolsch"), Rocky Mountain Metal Container (“RMMC”), Rocky Mountain Bottle Company (“RMBC”) and Truss LP ("Truss"). Our unconsolidated VIEs are BRI and BDL.
Both BRI and BDL have outstanding third-party debt which is guaranteed by their respective shareholders. As a result, we have a guarantee liability of $35.9 million and $38.1 million recorded as of December 31, 2018, and December 31, 2017, respectively, which is presented within accounts payable and other current liabilities on the consolidated balance sheets and represents our proportionate share of the outstanding balance of these debt instruments. The carrying value of the guarantee liability equals fair value, which considers an adjustment for our own non- performance risk and is considered a Level 2 measurement. The offset to the guarantee liability was recorded as an adjustment to our respective equity method investment within the consolidated balance sheets. The resulting change in our equity method investments during the year due to movements in the guarantee represents a non-cash investing activity.
## Equity Method Investments
Brewers' Retail Inc.
BRI is a beer distribution and retail network for the Ontario region of Canada, with majority of the ownership residing with MCC, Labatt Breweries of Canada LP (a subsidiary of ABI) and Sleeman Breweries Ltd. (a subsidiary of Sapporo International). BRI charges its owners administrative fees that are designed so the entity operates on a cash neutral basis. This
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Amounts due to and due from affiliates as of December 31, 2018, and December 31, 2017, respectively, are as follows:
<img src='content_image/1041234.jpg'>
## Consolidated VIEs
## Rocky Mountain Metal Container
RMMC, a Colorado limited liability company, is a joint venture with Ball Corporation in which we hold a 50% interest. Our U.S. business has a can and end supply agreement with RMMC. Under this agreement, we purchase substantially all of the output of RMMC. RMMC manufactures cans and ends at our facilities, which RMMC is operating under a use and license agreement. As RMMC is a limited liability company (“LLC”), the tax consequences flow to the joint venture partners.
## Rocky Mountain Bottle Company
RMBC, a Colorado limited liability company, is a joint venture with Owens-Brockway Glass Container, Inc. in which we hold a 50% interest. Our U.S. business has a supply agreement with RMBC under which we agree to purchase output approximating the agreed upon annual plant capacity of RMBC. RMBC manufactures bottles at our facilities, which RMBC is operating under a lease agreement. As RMBC is an LLC, the tax consequences flow to the joint venture partners.
## Cobra U.K.
We hold a 50.1% interest in Cobra U.K., which owns the worldwide rights to the Cobra beer brand (with the exception of the Indian sub- continent, owned by Cobra India). The noncontrolling interest is held by the founder of the Cobra beer brand. We consolidate the results and financial position of Cobra U.K., and it is reported within our Europe operating segment.
## Grolsch
Grolsch is a joint venture between us and Royal Grolsch N.V. (a member of Asahi Group Holdings, Ltd.) in which we hold a 49% interest. The Grolsch joint venture markets Grolsch brands in the U.K. and the Republic of Ireland. The majority of the Grolsch brands are produced by us under a contract brewing arrangement with the joint venture. MCBC and Royal Grolsch N.V. sell beer to the joint venture, which sells the beer back to MCBC (for onward sale to customers) for a price equal to what it paid, plus a marketing and overhead charge and a profit margin. Grolsch is a taxable entity in Europe. Accordingly, income tax expense in our consolidated statements of operations includes taxes related to the entire income of the joint venture. We consolidate the results and financial position of Grolsch and it is reported within our Europe operating segment.
## Truss
On October 4, 2018, a wholly-owned subsidiary within our Canadian business completed the formation of Truss LP, an independent Canadian joint venture with HEXO Corp. ("HEXO") to pursue opportunities to develop, produce and market non-alcoholic, cannabis-infused beverages once legal in Canada. Truss is structured as a standalone start-up company with its own board of directors and an independent management team. We maintain a 57.5% controlling interest in Truss, which is a VIE that is consolidated. In connection with the formation of Truss, HEXO also issued warrants to our Canadian subsidiary, which are further discussed in Note 16, "Derivative Instruments and Hedging Activities."
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As of
<img src='content_image/1049144.jpg'>
The balances in the table above reflect the change in tax status of our investment in MillerCoors, which effective in 2018, is no longer a partnership for U.S. tax purposes. As a result of this change, the associated net deferred tax liability balance for the partnership investment in MillerCoors, previously in the partnership investments line item, has been reallocated in 2018 into its respective individual deferred tax asset and liability classifications above.
The overall increase in net deferred tax liabilities of $228.4 million in 2018 is primarily attributable to the amortization of goodwill and indefinite-lived intangible assets resulting from the Acquisition for U.S. tax purposes, as well as incremental tax depreciation of fixed assets. Additionally, our deferred tax balances are also impacted by foreign exchange rates, as a significant amount of our deferred tax assets and liabilities are in foreign jurisdictions.
Our deferred tax valuation allowances are primarily the result of uncertainties regarding the future realization of recorded tax benefits on tax loss carryforwards from operations in various jurisdictions. The measurement of deferred tax assets is reduced by a valuation allowance if, based upon available evidence, it is more likely than not that the deferred tax assets will not be realized. We have evaluated the realizability of our deferred tax assets in each jurisdiction by assessing the adequacy of expected taxable income, including the reversal of existing temporary differences, historical and projected operating results and the availability of prudent and feasible tax planning strategies. Based on this analysis, we have determined that the valuation allowances recorded in each period presented are appropriate.
We have deferred tax assets for U.S. tax carryforwards that expire between 2019 and 2038 of $76.7 million and $35.8 million as of December 31, 2018, and December 31, 2017, respectively. We have foreign tax loss carryforwards that expire between 2019 and 2038 of $195.0 million and $238.6 million as of December 31, 2018, and December 31, 2017, respectively. We have foreign tax loss carryforwards that do not expire of $984.6 million and $963.4 million as of December 31, 2018, and December 31, 2017, respectively.
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## Canada Segment
• Headquarters: Toronto, Ontario
• Approximately 2,600 employees
• Canada's second largest brewer by volume and North America's oldest beer company, selling approximately 32% of the total 2018 Canada beer market
• Currently operating five primary breweries and four craft breweries
We brew, market, sell and distribute a wide variety of beer brands nationally. Our portfolio has leading brands in all major product and price segments. In 2018, Coors Light had an approximate 10% market share and was the second largest selling beer brand in Canada, and Molson Canadian had an approximate 5% market share and was the fourth largest selling beer in Canada. As a result of the Acquisition, the Miller brands returned to our Canada business.
The Canada segment also includes our partnership arrangements related to the distribution of beer in Ontario, Brewers' Retail Inc. ("BRI"), and in the Western provinces, Brewers' Distributor Ltd. ("BDL"). BRI and BDL are accounted for under the equity method of accounting. The majority of ownership in BRI resides with MCC, Labatt Breweries of Canada LP (a subsidiary of ABI) and Sleeman Breweries Ltd. (a subsidiary of Sapporo International). BDL is jointly owned by MCC and ABI.
In line with our strategic initiatives to expand our craft portfolio, the Canada segment acquired two craft breweries in Quebec, Le Trou du Diable and Brasseurs de Montréal, Inc. in 2017 and in 2016, respectively. There were no additional acquisitions during 2018. However, on October 4, 2018, a wholly-owned subsidiary within our Canadian business completed the formation of an independent Canadian joint venture, Truss LP ("Truss"), with HEXO Corp. ("HEXO") to pursue opportunities to develop, produce and market non-alcoholic, cannabis-infused beverages once legal in Canada. Truss is structured as a standalone start-up company with its own board of directors and an independent management team and we maintain a 57.5% controlling interest in the joint venture.
## Sales and Distribution
In Canada, provincial governments regulate the beer industry, particularly with regard to the pricing, mark-up, container management, sale, distribution and advertising of beer. Distribution and the retail sale of alcohol products involve a wide range and varied degree of Canadian government control through their respective provincial liquor boards. See below discussion for details by province.
## Channels
In Canada, the on-premise channel includes sales in bars and restaurants. In Ontario and Western Canada, we use jointly-owned distribution systems to deliver beer to on-premise customers along with products from Labatt Breweries of Canada LP and Sleeman Breweries Ltd. In Quebec and Eastern Canada, we primarily deliver directly. The on-premise channel, and relationships with customers, are highly regulated and the regulations differ significantly across different provincial jurisdictions.
The off-premise channel includes sales to convenience stores, grocery stores, liquor stores and other specialty retail outlets, including "The Beer Store" in Ontario, which is the world's largest beer retailer and is co-owned by Ontario's three largest brewers. The off-premise channel is highly regulated and differs significantly across different provincial jurisdictions.
The following table reflects the industry channel trends over the last five years in Canada.
<img src='content_image/1022498.jpg'>
## Province of Ontario
In Ontario, beer is primarily purchased at retail outlets operated by BRI, at government-regulated retail outlets operated by the Liquor Control Board of Ontario ("LCBO"), at approved agents of the LCBO, at certain licensed grocery stores, or at any bar, restaurant, or tavern licensed by the LCBO to sell alcohol for on-premise consumption. The BRI retail outlets operate under The Beer Store name. Brewers may deliver directly to BRI's outlets or may choose to use BRI's distribution centers to access retail stores in Ontario, the LCBO system, the grocery channel and licensed establishments.
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(4) As a result of our continued strategic review of our European supply chain network, during 2018, 2017 and 2016, we incurred charges consisting primarily of accelerated depreciation in excess of normal depreciation related to the closure of our Burton South brewery and other associated closure costs. The Burton South Brewery closed during the first quarter of 2018. Additionally, as part of this review, related to the closures of our Plovdiv brewery in Bulgaria and Alton brewery in the U.K., during 2018, 2017 and 2016, we recorded asset abandonment related special charges.
Separately, during 2017 we completed the sale of land related to our previously closed Plovdiv brewery and received net cash proceeds of $8.2 million and recognized a gain of $4.6 million within special items.
(5) Based on an interim impairment assessment performed during the second quarter of 2016, which was triggered by the enactment of total alcohol prohibition in the state of Bihar, India on April 5, 2016, we recorded an impairment loss in the second quarter of 2016. See Note 10, "Goodwill and Intangible Assets" for additional details.
(6) During the third quarter of 2016, we received the final settlement of insurance proceeds related to losses incurred by our Europe business from flooding in Serbia, Bosnia and Croatia that occurred during 2014.
(7) On October 11, 2016, we completed the Acquisition and recorded a revaluation gain on the excess of the estimated fair value remeasurement for our pre-existing 42% interest in MillerCoors over its carrying value, as well as the reclassification of the loss related to MCBC's historical AOCI on our 42% interest in MillerCoors within special items, net in the fourth quarter of 2016. See Note 4, "Acquisition and Investments" for further details.
(8) Represents charges related to the exit of our China business in 2018, consisting primarily of the reclassification of the associated cumulative foreign currency translation adjustment from AOCI upon substantial liquidation. See Note 14, "Accumulated Other Comprehensive Income (Loss)" for further details.
(9) During the first quarter of 2018, we recorded the settlement proceeds related to the Adjustment Amount as a gain within special items, net in our consolidated statement of operations in our Corporate segment and within cash provided by operating activities within our consolidated statement of cash flows. See Note 4, "Acquisition and Investments" for further details.
## Restructuring Activities
Beginning in 2016, restructuring initiatives related to the integration of MillerCoors after the completion of the Acquisition were implemented in order to operate a more efficient business and achieve cost saving targets which to date resulted in reduced employment levels by approximately 110 employees. Total restructuring costs related to integration initiatives were $1.6 million in 2017 and $9.3 million in 2016, representing the majority of the charges within the table below by segment. Subsequently, during the third quarter of 2018, we initiated restructuring activities in the U.S. in order to align our cost base with our scale of business. As a result, we reduced U.S. employment levels by approximately 300 employees in the fourth quarter of 2018. Additionally, we also initiated global restructuring activities during the fourth quarter of 2018, and reduced employment levels across the business by approximately 20 employees. Severance costs related to these restructuring activities were recorded as special items in our consolidated statements of operations. As we continually evaluate our cost structure and seek opportunities for further efficiencies and cost savings as part of these initiatives, we may incur additional restructuring related charges in the future, however, we are unable to estimate the amount of charges at this time.
We have continued our ongoing assessment of our supply chain strategies across our segments in order to align with our cost saving objectives. As part of this strategic review, which began in 2014, we have had restructuring activities related to the closure or planned closure of breweries, as well as activities related to business efficiencies. As a result, we have reduced employment levels by a total of 456 employees. Consequently, we recognized severance and other employee-related charges, which we have recorded as special items within our consolidated statements of operations. We will continue to evaluate our supply chain network and seek opportunities for further efficiencies and cost savings, and we therefore may incur additional restructuring related charges or adjustments to previously recorded charges in the future, however, we are unable to estimate the amount of charges at this time.
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## 11. Debt
## Debt Obligations
<img src='content_image/1060332.jpg'>
(1) Prior to Molson Coors International, L.P., a Delaware limited partnership and wholly-owned subsidiary of MCBC ("Molson Coors International L.P."), issuing our CAD 500 million 2.75% notes due September 18, 2020 ("CAD 500 million notes"), and CAD 400 million 2.25% notes due September 18, 2018 ("CAD 400 million notes", and together with the CAD 500 million notes, the "2015 Notes"), on September 18, 2015, we entered into forward starting interest rate swap agreements to hedge the interest rate volatility for a 10 year period. We settled these swaps at the time of issuance of the 2015 Notes and are amortizing a portion of the resulting loss from AOCI to interest expense over the remaining term of the 2015 Notes as well as over a portion of the 2016 Notes defined below up to the full 10-year term of the interest rate swap agreements. The amortizing loss will increase our effective cost of borrowing compared to the stated coupon rates by 0.65% and 0.60% on each of the CAD 500 million notes due in 2020 and 2026, respectively. See Note 16, "Derivative Instruments and Hedging Activities" for further details on the forward starting interest rate swaps. During the third quarter of 2018, we repaid the CAD 400 million notes with cash on hand.
(2) On July 7, 2016, MCBC issued approximately $5.3 billion senior notes with portions maturing from July 15, 2019, through July 15, 2046 ("2016 USD Notes"), and EUR 800.0 million senior notes maturing July 15, 2024 ("2016 EUR Notes"), and Molson Coors International L.P., completed a private placement of CAD 1.0 billion senior notes maturing July 15, 2023, and July 15, 2026 ("2016 CAD Notes"), in order to partially fund the financing of the Acquisition (2016 USD Notes, 2016 EUR Notes and 2016 CAD Notes, collectively, the "2016 Notes"). These issuances resulted in total proceeds of approximately $6.9 billion, net of underwriting fees and discounts of $36.5 million and $17.7 million,
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## 14. Accumulated Other Comprehensive Income (Loss)
<img src='content_image/1040415.jpg'>
(1) Upon completion of the Acquisition on October 11, 2016, we recorded a loss of $458.3 million within special items, net upon reclassification of our accumulated other comprehensive loss related to our historical 42% interest in MillerCoors. The associated income tax benefit of $200.1 million was also reclassified and recorded as a component of the income tax benefit (expense) line item on the consolidated statement of operations. See Note 4, "Acquisition and Investments" for further details. The remaining AOCI of our equity method investments is related to changes to BRI and BDL pension obligations.
(2) As a result of exiting our China business, the associated cumulative foreign currency translation adjustment was reclassified from AOCI and recognized within special items, net upon substantial liquidation. See Note 7, "Special Items" for further details.
We have significant levels of net assets denominated in currencies other than the USD due to our operations in foreign countries, and therefore we recognize OCI gains and/or losses when those items are translated to USD. The foreign currency translation losses recognized during 2018 were due to the weakening of the CAD, GBP and other currencies of our Europe operations versus the USD. The foreign currency translation gains recognized during 2017 were due to the strengthening of
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Medicare Prescription Drug Improvement and Modernization Act of 2003 (“the Act”) because the prescription drug benefits provided under the Company's postretirement health plan for Medicare eligible retirees generally require lower premiums from covered retirees and have lower co- payments and deductibles than the benefits provided in Medicare Part D and, accordingly, are actuarially equivalent to or better than the benefits provided under the Act. The benefits paid, including prescription drugs, were $37.1 million in 2018, $36.6 million in 2017 and $9.0 million for the post-Acquisition period of October 11, 2016, through December 31, 2016. Subsidies of $0.3 million for both 2018 and 2017, and $0.1 million for the post-Acquisition period of October 11, 2016, through December 31, 2016, were received.
As a result of the Acquisition, MillerCoors' results of operations became fully consolidated by MCBC, and, therefore, for the year ended December 31, 2016, the consolidated statement of operations includes MillerCoors' pension and OPEB expenses attributable to the period from October 11, 2016, to December 31, 2016. MillerCoors' pension and OPEB plans were recorded at fair value upon close of the Acquisition.
## Defined Benefit and OPEB Plans
## Net Periodic Pension and OPEB Cost (Benefit)
We have adopted the FASB's new guidance related to the classification of defined benefit pension and other postretirement plan costs.
Specifically, the new guidance requires us to report only the service cost component in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period; while the other components of net benefit cost are now presented in the consolidated statements of operations separately from the service cost component and outside of operating income. We have also determined that only service cost will be reported within each operating segment and all other components will be reported within the Corporate segment. See further discussion in Note 2, "New Accounting Pronouncements."
<img src='content_image/1053564.jpg'>
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<img src='content_image/1021055.jpg'>
The accumulated benefit obligation for our defined benefit pension plans was approximately $4.9 billion and $5.6 billion as of December 31, 2018, and December 31, 2017, respectively. The $130.8 million decrease in the net underfunded status of our aggregate pension and OPEB plans from December 31, 2017, to December 31, 2018, was primarily driven by the increase in discount rates. Our underfunded status also includes the impact of the High Court ruling in the U.K. related to equalizing pension benefits between men and women, which had an immaterial impact to our net underfunded status.
As of December 31, 2018, our defined benefit plan in the U.K. and certain defined benefit plans in the U.S. and Canada were overfunded as a result of our ongoing de-risking strategy. Information for our defined benefit plans that had aggregate accumulated benefit obligations and projected benefit obligations in excess of plan assets as of December 31, 2018, is as follows:
<img src='content_image/1021056.jpg'>
Information for OPEB plans with an accumulated postretirement benefit obligation in excess of plan assets has been disclosed above in "Obligations and Changes in Funded Status" as all of our OPEB plans are unfunded.
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## Accumulated Other Comprehensive Income (Loss)
Amounts recognized in AOCI not yet recognized as components of net periodic pension and OPEB cost, pretax, were as follows:
<img src='content_image/1055455.jpg'>
Changes in plan assets and benefit obligations recognized in OCI, pretax, were as follows:
<img src='content_image/1055456.jpg'>
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## Assumptions
Periodic pension and OPEB cost is actuarially calculated annually for each individual plan based on data available at the beginning of each year. Assumptions used in the calculation include the settlement discount rate selected and disclosed at the end of the previous year as well as other assumptions detailed in the table below. The weighted-average rates used in determining the periodic pension and OPEB cost for the fiscal years 2018, 2017 and 2016 were as follows:
<img src='content_image/1040582.jpg'>
(1) We develop our EROA assumptions annually with input from independent investment specialists including our actuaries, investment consultants, plan trustee and other specialists. Each EROA assumption is based on historical data, including historical returns, historical market rates and is calculated for each plan's individual asset class. The calculation includes inputs for interest, inflation, credit, and risk premium (active investment management) rates and fees paid to service providers. We consider our EROA to be a significant management estimate. Any material changes in the inputs to our methodology used in calculating our EROA could have a significant impact on our reported defined benefit pension plans' expense.
Benefit obligations are actuarially calculated annually at the end of each year based on the assumptions detailed in the table below. Obligations under the OPEB plans are determined by the application of the terms of medical, dental, vision and life insurance plans, together with relevant actuarial assumptions and heath care cost trend rates. The weighted-average rates used in determining the projected benefit obligation for defined pension plans and the accumulated postretirement benefit obligation for OPEB plans, as of December 31, 2018, and December 31, 2017, were as follows:
<img src='content_image/1040581.jpg'>
The change to the weighted-average discount rates used for our defined benefit pension plans and postretirement plans as of December 31, 2018, from December 31, 2017, is primarily the result of overall market changes during 2018.
## Investment Strategy
The obligations of our defined benefit pension plans in the U.S., Canada and the U.K. are supported by assets held in trusts for the payment of future benefits. The business segments are obligated to adequately fund these asset trusts. The underlying investments within our defined benefit pension plans include: cash and short-term instruments, debt securities, equity securities, investment funds, and other investments including derivatives, hedge fund of funds and real estate. Investment allocations reflect the customized strategies of the respective plans.
The plans use liability driven investment strategies in managing defined pension benefits. For all defined benefit pension plan assets the plans have the following primary investment objectives:
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(1) optimize the long-term return on plan assets at an acceptable level of risk and manage projected future cash contributions;
(2) maintain a broad diversification across asset classes and among investment managers; and
(3) manage the risk level of the plans' assets in relation to the plans' liabilities.
Each plan's respective allocation targets promote optimal expected return and volatility characteristics given a focus on a long-term time horizon for fulfilling the plans' obligations. All assets are managed by external investment managers with a mandate to either match or outperform their benchmark. The plans used different asset managers in the U.S., U.K. and Canada and each plan's respective asset allocation could be impacted by a change in asset managers.
Our investment strategies for our defined benefit pension plans also consider the funding status for each plan. For defined benefit pension plans that are highly funded, assets are invested primarily in fixed income holdings that have a similar duration to the associated liabilities. For plans with lower funding levels, the fixed income component is managed in a similar manner to the highly funded plans. In addition to this liability- matching fixed income allocation, these plans also contain exposure to return generating assets including: equities, real estate, debt, and other investments held with the goal of producing higher returns, which may also have a higher risk profile. These investments are diversified by investing globally with limitations placed on issuer concentration.
Both our U.K. and Canadian plans hedge a portion of the foreign exchange exposure between plan assets that are not denominated in the local plan currency and the local currency as the Canadian and U.K. pension liabilities will be settled in CAD and GBP, respectively.
## Target Allocations
The following compares target asset allocation percentages with actual asset allocations on a weighted-average asset basis as of December 31, 2018:
<img src='content_image/1035317.jpg'>
During the first quarter of 2019, we adjusted our target allocation of plan assets to align with our updated investment strategy. These allocation changes are reflected in our weighted-average EROA assumptions for 2019.
## Significant Concentration Risks
We periodically evaluate our defined benefit pension plan assets for concentration risks. As of December 31, 2018, we did not have any individual underlying asset position that composed a significant concentration of each plan's overall assets. However, we currently have significant plan assets invested in U.K., U.S. and Canadian government fixed income holdings. A provisional credit rating downgrade for any of these governments could negatively impact the asset values.
Further, as our benefit plans maintain exposure to non-government investments, a significant system-wide increase in credit spreads would also negatively impact the reported plan asset values. In general, equity and fixed income risks have been mitigated by company-specific concentration limits and by utilizing multiple equity managers. We do have significant amounts of assets invested with individual fixed income and hedge fund managers, therefore, the plans use outside investment consultants to aid in the oversight of these managers and fund performance.
## Valuation Techniques
We use a variety of industry accepted valuation techniques to value our plan assets. The techniques vary depending upon instrument type. Whenever possible, we prioritize the use of observable market data in our valuation processes. We use market, income and cost approaches to value our plan assets as of period end. See Note 1, "Basis of Presentation and Summary of Significant Accounting Policies" for additional information on our fair value methodologies and accounting policies. We have not changed our fair value techniques used to value plan assets this year.
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The following presents our total fair value of plan assets including the NAV per share practical expedient for our defined benefit pension plan assets:
<img src='content_image/1039565.jpg'>
The following presents our fair value hierarchy for our defined benefit pension plan assets excluding investments using the NAV per share practical expedient (in millions):
<img src='content_image/1039566.jpg'>
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forecasted transaction affects earnings. However, if it is no longer probable that a forecasted transaction will occur by the end of the originally specified time period or within an additional two-month period of time thereafter, the gains and losses in AOCI are recognized immediately in earnings. In all situations in which hedge accounting is discontinued and the derivative remains outstanding, we carry the derivative at its fair value on the consolidated balance sheets until maturity, recognizing future changes in the fair value in current period earnings.
## Significant Derivative/Hedge Positions
## Derivative Activity Related to the Acquisition
During the first quarter of 2016, we entered into swaption agreements with a total notional amount of $855.0 million to economically hedge a portion of our long-term debt issuance with which we partially funded the Acquisition. We paid upfront premiums of $37.8 million for the option to enter into and exercise swaps with a forward starting effective date. These swaptions were not designated in hedge accounting relationships as the hedges were entered into in association with the Acquisition and, accordingly, all mark-to-market fair value adjustments were reflected within interest expense. During the second quarter of 2016, we terminated and cash settled these swaptions in anticipation of the issuance of the 2016 Notes, resulting in cash proceeds of $1.4 million.
Separately, prior to issuing the EUR Notes and the CAD Notes on July 7, 2016, we entered into foreign currency forward agreements in the second quarter of 2016 with a total notional amount of EUR 794.6 million and CAD 965.5 million, representing a majority of the anticipated net proceeds from the issuance of the respective CAD Notes and EUR Notes, to economically hedge the foreign currency exposure of the associated notes against the USD prior to issuance and to convert the proceeds to USD upon issuance through gross settlement. We settled these foreign currency forwards on July 7, 2016, resulting in a loss of $3.6 million, and received the USD necessary, along with the USD Notes, to complete our financing needs for the Acquisition. These foreign currency forwards were not designated in hedge accounting relationships, and, accordingly, the mark-to-market fair value adjustments and resulting unrealized losses were recorded to other income (expense).
On July 7, 2016, concurrent with the issuance of the EUR Notes, we designated the principal EUR 800 million of the EUR Notes as a non- derivative financial net investment hedge of our investment in our Europe business in order to hedge a portion of the related foreign currency translational impacts, and, accordingly, record changes in the carrying value of the EUR Notes due to fluctuations in the spot rate to AOCI. See Note 11, "Debt" for further discussion of the EUR Notes and CAD Notes.
## Interest Rate Swaps
In the first quarter of 2017, we entered into interest rate swaps with an aggregate notional amount of $1.0 billion to economically convert our fixed rate $1.0 billion 2017 USD Notes to floating rate debt. We received fixed interest payments semi-annually at a rate of 1.90% and 2.25% per annum on our $500 million senior notes due March 15, 2019, and $500 million senior notes due March 15, 2020, respectively, and paid a rate to our counterparties based on a credit spread plus the one-month LIBOR rate, thereby effectively exchanging a fixed interest obligation for a floating interest obligation.
We entered into these interest rate swap agreements to minimize exposure to changes in the fair value of each of our $500 million notes that results from fluctuations in the benchmark interest rate, specifically LIBOR. We designated these swaps as fair value hedges and determined that there was zero ineffectiveness. The changes in fair value of derivatives designated as fair value hedges and the offsetting changes in fair value of the hedged item were recognized in earnings. The changes in fair value of the two $500 million interest rate swaps were recorded in interest expense in our consolidated statement of operations and were fully offset by changes in fair value of the two $500 million notes attributable to the benchmark interest rate, also recorded to interest expense.
During the fourth quarter of 2017, we voluntarily settled our aggregate notional amount of $1.0 billion which resulted in net cash payments of $3.5 million, representing the cumulative adjustments to the carrying value of the notes from inception to termination. At the time of settlement we ceased adjusting the carrying value of the two $500 million notes for the fair value movements and these cumulative adjustments are now being amortized as a charge to interest expense over the expected remaining term of the respective note. See Note 11, "Debt" for additional details.
Separately, in prior years, we also entered into similar interest rate swap agreements to economically convert our fixed rate $500 million 3.5% notes due 2022 to floating rate debt. These interest rate swap agreements were also previously voluntarily cash settled, at which time we ceased adjusting the carrying value of the notes for the fair value movements. The cumulative adjustments which increased the carrying value of the notes are being amortized as a benefit to interest expense over the expected remaining term of the notes. See Note 11, "Debt" for additional details.
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## Known Trends and Competitive Conditions
## 2018 Canada Beer Industry Overview
The Canadian brewing industry is a mature market and ABI and MCBC are the two largest brewers. It is characterized by aggressive competition for volume and market share from regional brewers, microbrewers and certain foreign brewers, as well as our main domestic competitor. These competitive pressures require significant annual investment in marketing and selling activities. In 2018, the Ontario and Québec markets accounted for approximately 61% of the total beer market in Canada.
There are three major beer price segments: above premium, which includes craft and most imports; premium, which includes the majority of domestic brands and the light sub-segment; and value (below premium). Since 2001, the premium beer segment in Canada has gradually lost volume to the above premium and value segments.
The beer industry has declined in five of the last six years. Aging population and strong competition from other alcohol beverages have been the main contributors to the declining state of the beer industry.
The following table summarizes the estimated percentage market share by volume of beer (including adjacencies, such as cider) and other alcohol beverages, including wine and spirits, as a component of the overall Canadian alcohol market over the last five years, for which data is currently available. We anticipate that 2018 data, when available, will reflect a continuation of the recent consumer trends. Note that percentages reflect estimates based on market data currently available.
<img src='content_image/1038675.jpg'>
## Our Competitive Position
Our brands compete with competitor beer brands and other alcohol beverages, including wine and spirits, and thus our competitive position is affected by consumer preferences among these other categories. Our brand portfolio gives us strong representation in all major beer segments.
The following table summarizes the estimated percentage share of the Canadian beer market represented by MCBC, ABI and all other brewers over the last five years. Note that the sum of the percentages below may not equal 100% due to rounding. Current year percentages reflect estimates based on market data currently available.
<img src='content_image/1038682.jpg'>
(1) The decrease in MCBC's share in 2015 was largely driven by the loss of the contract with Miller Brewing Company ("Miller"), under which we had exclusive rights to distribute certain Miller brands in Canada and was terminated effective March 2015. As a result of the Acquisition, beginning October 11, 2016, these Miller brands returned to our Canada business.
## Regulation
In Canada, provincial governments regulate the production, marketing, distribution, selling and pricing of beer (including the establishment of minimum prices), and impose commodity taxes and license fees in relation to the production, distribution and sale of beer. In addition, the federal government regulates the advertising, labeling, quality control, and international trade of beer, and also imposes commodity taxes on both domestically produced and imported beer. In 2018, our Canada segment excise taxes were approximately $54 per hectoliter sold on a reported basis. Further, certain bilateral and multilateral treaties entered into by the federal government, provincial governments and certain foreign governments, especially with the United States, affect the Canadian beer industry.
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of December 31, 2018. Our total estimate of the indemnity liability as of December 31, 2018, was $10.3 million, of which $4.2 million was classified as a current liability, and $6.1 million classified as non-current.
Our estimates consider a number of scenarios for the ultimate resolution of these issues, the probabilities of which are influenced not only by legal developments in Brazil but also by management's intentions with regard to various alternatives that could present themselves leading to the ultimate resolution of these issues. The liabilities are impacted by changes in estimates regarding amounts that could be paid, the timing of such payments, adjustments to the probabilities assigned to various scenarios and foreign currency exchange rates. Our indemnity also covers fees and expenses that Kaiser incurs to manage the cases through the administrative and judicial systems.
Additionally, we also provided FEMSA with indemnity related to all other tax, civil, and labor contingencies existing as of the date of sale. In this regard, however, FEMSA assumed their full share of all of these contingent liabilities that had been previously recorded and disclosed by us prior to the sale on January 13, 2006. However, we may have to provide indemnity to FEMSA if those contingencies settle at amounts greater than those amounts previously recorded or disclosed by us. We will be able to offset any indemnity exposures in these circumstances with amounts that settle favorably to amounts previously recorded. Our exposure related to these indemnity claims is capped at the amount of the sales price of the 68% equity interest of Kaiser, which was $68.0 million. As a result of these contract provisions, our estimates include not only probability-weighted potential cash outflows associated with indemnity provisions, but also probability-weighted cash inflows that could result from favorable settlements, which could occur through negotiation or settlement programs arising from the federal or any of the various state governments in Brazil. The recorded value of the tax, civil, and labor indemnity liability was $4.4 million as of December 31, 2018, which is classified as non- current. For the remaining portion of our indemnity obligations, not deemed probable, we continue to utilize probability-weighted scenarios in determining the value of the indemnity obligations.
Future settlement procedures and related negotiation activities associated with these contingencies are largely outside of our control. The sale agreement requires annual cash settlements relating to the tax, civil, and labor indemnities. Indemnity obligations related to purchased tax credits must be settled upon notification of FEMSA's settlement. Due to the uncertainty involved with the ultimate outcome and timing of these contingencies, significant adjustments to the carrying values of the indemnity obligations have been recorded to date, and additional future adjustments may be required. These liabilities are denominated in Brazilian Reais and are therefore, subject to foreign exchange gains or losses. As a result, these foreign exchange gains and losses are the only impacts recorded within other income (expense), net.
The table below provides a summary of reserves associated with the Kaiser indemnity obligations from December 31, 2015, through December 31, 2018:
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## MOLSON COORS BREWING COMPANY AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (IN MILLIONS)
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## 20. Quarterly Financial Information (Unaudited)
The 2017 quarterly information reflects retrospective adjustments for the adoption of the new accounting guidance related to defined benefit pension and other postretirement plans as discussed in Note 2, "New Accounting Pronouncements."
<img src='content_image/1048553.jpg'>
The sum of the quarterly net income per share amounts may not agree to the full-year net income per share amounts. We calculate net income per share based on the weighted-average number of outstanding shares during the reporting period. The average number of shares fluctuates throughout the year and can therefore produce a full-year result that does not agree to the sum of the individual quarters.
## Correction of Previously Issued Unaudited Condensed Consolidated Financial Statements for Income Tax Accounting Errors
As a result of the corrections of the income tax accounting errors discussed in Note 1, "Basis of Presentation and Summary of Significant Accounting Policies," we have corrected our previously disclosed unaudited condensed consolidated statements of operations for the three month and year-to-date periods ended June 30, 2017, September 30, 2017, and December 31, 2017, and the unaudited condensed consolidated balance sheets as of the end of each of the quarterly periods in 2017 and 2018. Specifically, in addition to the impacts of the errors described in Note 1, "Basis of Presentation and Summary of Significant Accounting Policies," we have further corrected our 2017 unaudited interim financial statements to increase the deferred tax liability and corresponding deferred tax expense by $2.9 million for the three months ended June 30, 2017, and to decrease the deferred tax liability and corresponding deferred tax expense by $26.2 million and $128.1 million for the three months ended September 30, 2017, and December 31, 2017, respectively. There was no impact of the corrections on the unaudited condensed consolidated statements of operations for the three months ended March 31, 2017, or for the three months and year-to-date periods ended March 31, 2018, June 30, 2018, and September 30, 2018. We assessed the applicable guidance issued by the SEC and the FASB and concluded that these errors in the 2017 and 2018 quarterly and year-to-date financial statements were not material, individually or in the aggregate, to MCBC’s previously issued unaudited interim condensed consolidated financial statements for the applicable interim periods included in our Quarterly Reports on Form 10-Q for the aforementioned quarterly periods. The errors in the three months ended December 31, 2017, were material and as such are described as restated.
The revision of our previously issued unaudited condensed consolidated financial statements for the three months ended March 31, 2018, three and six months ended June 30, 2018, and the three and nine months ended September 30, 2018, will be affected in connection with our quarterly filings for the quarters ending March 31, June 30, and September 30, 2019, respectively.
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years ended December 31, 2017, and December 31, 2016, and the correction of the unaudited quarterly financial information for fiscal years 2018 and 2017. Additionally, this material weakness could result in misstatements to the aforementioned account balances or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected.
As a result of the material weakness in internal control over financial reporting described above, management has concluded that we did not maintain effective internal control over financial reporting as of December 31, 2018.
An independent registered public accounting firm, PricewaterhouseCoopers LLP, has audited the effectiveness of our internal control over financial reporting as of December 31, 2018, as stated in their report which appears in Part II—Item 8 Financial Statements and Supplementary Data.
## Management's Plan for Remediation of the Material Weakness
In response to the material weakness described above, with the oversight of the Audit Committee of our Board of Directors, management is currently evaluating our policies and procedures related to the accounting for income taxes and plans to design and implement adequate internal controls to ensure that (i) the income tax effects of acquired partnership interests are properly accounted for and disclosed in the period of acquisition, and (ii) the resulting investment in partnership deferred income tax assets and liabilities are assessed and reconciled periodically to the book-tax differences in the underlying assets and liabilities within the partnership to determine whether any adjustment is necessary.
The remediation efforts are intended both to address the identified material weakness and to enhance our overall financial control environment. Management is committed to continuous improvement of the company’s internal control over financial reporting and will continue to diligently review the company’s internal control over financial reporting.
## Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)) during the quarter ended December 31, 2018, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
## ITEM 9B. OTHER INFORMATION
None.
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## ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
## (a) Financial Statements, Financial Statement Schedules and Exhibits
## PART IV
The following are filed or incorporated by reference as a part of this Annual Report on Form 10-K:
(1) Management's Report
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Operations for the years ended December 31, 2018, December 31, 2017, and December 31, 2016
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2018, December 31, 2017, and December 31, 2016
Consolidated Balance Sheets as of December 31, 2018, and December 31, 2017
Consolidated Statements of Cash Flows for the years ended December 31, 2018, December 31, 2017, and December 31, 2016
Consolidated Statements of Stockholders' Equity and Noncontrolling Interests for the years ended December 31, 2018, December 31, 2017, and December 31, 2016
Notes to Consolidated Financial Statements
(2) Schedule II—Valuation and Qualifying Accounts for the years ended December 31, 2018, December 31, 2017, and December 31, 2016
(3) Exhibit list
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focus brands. Our focus brands are Coors Light , Miller Lite and Miller Genuine Draft , which are aligned with global priority brands and account for the majority of our volumes. The International segment's portfolio of beers competes within the above premium category in most of our markets. Our principal competitors include large global brewers, as well as local brewers. As our International segment's objective is to grow and expand our business, we are developing scale and building market share in the countries where we operate. Many of the markets in which we operate are considered emerging beer markets, with other brewers controlling the majority of the market share. Our beers compete not only with similar products from competitors, but also with other alcohol beverages, including wines, spirits, and ciders, and thus our competitive position is affected by consumer preferences between and among these other categories.
As part of the acquisition of the Miller International Business, which we acquired in the fourth quarter of 2016, we entered into various Transitional Service Agreements (“TSAs”) with local SABMiller and now ABI owned entities for services including the selling, distribution and production of Miller brands. We have successfully created a presence and commercial routes to market related to the Miller brands, but continue to leverage production TSAs, which are set to expire in October 2019, in certain markets. We are in the process of establishing alternative production for the Miller brands and do not currently anticipate any material disruption in the supply of our products after the currently-scheduled expiration of the production TSAs.
## Latin America
In Latin America, we use a combination of export models and license agreements to sell Blue Moon, Coors Light, Miller Genuine Draft, Miller High Life, Miller Lite and other brands. In our export model markets, we import beer from the U.S. and sell it through agreements with independent distributors. Our export markets include countries such as Dominican Republic, Paraguay and Puerto Rico. In license markets, such as Argentina, Colombia and Mexico, we have established exclusive licensing agreements with brewers and distributors for the manufacturing and distribution of our products. In Honduras, Panama and Chile we rely on a combination of export and license agreements.
## Asia Pacific
Our operations in the Asia Pacific region include markets such as Australia, India, Japan and South Korea. Our business in India consists primarily of operations in the states of Haryana, Punjab and Uttar Pradesh. Our consolidated India business produces, markets and sells a beer portfolio consisting of Thunderbolt, Miller Ace, Miller High Life and Carling Strong. We own three breweries in India (one of which is currently not operational as a result of the State of Bihar, India’s enactment of total alcohol prohibition in 2016), where we use high quality ingredients to brew our products, which are sourced through various contracts with local suppliers. We do not currently anticipate any significant disruption in the supply of these raw materials or brewing inputs in the near term.
Our Japan business imports our brands and sells through independent wholesalers. Our focus is on the marketing and selling of the Blue Moon, Coors Light and Zima brands. During the fourth quarter of 2018, we entered into an exclusive distribution agreement with Boon Rawd Trading International Co. Ltd, best known for its flagship brand, Singha . Under this agreement, we will be the exclusive importer, distributor, marketer and seller of Singha in Japan beginning January 2019. In Australia, we license our brands to a local partner that distributes locally produced and imported products including Blue Moon , Coors, Miller Genuine Draft, Miller Chill and other products for us. In South Korea, our brands include Blue Moon , Coors Light , Miller Genuine Draft , Miller Lite and Staropramen and are imported and sold through an independent distributor. During the first half of 2018, we decided to formally exit our business in China and we have subsequently completed the substantial liquidation of the corresponding entity.
## Africa
We sell Miller Genuine Draft in South Africa and Zambia. Miller Genuine Draft is produced in South Africa and sold through a local license agreement.
## Corporate
Corporate is not a reportable segment and primarily includes interest and certain other general and administrative costs that are not allocated to any of the operating segments. The majority of these corporate costs relate to worldwide administrative functions, such as corporate affairs, legal, human resources, information technology, finance, internal audit, insurance, ethics and compliance, risk management, global growth, supply chain and commercial initiatives, as well as acquisition, integration and financing costs associated with the Acquisition. Additionally, Corporate includes the results of our water resources and energy operations in Colorado as well as the unrealized changes in fair value on our commodity swaps not designated in hedging relationships recorded within cost of goods sold, which are later reclassified when realized to the segment in which the underlying exposure resides.
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material adverse effect on our business and financial results. See risk factors below under “Risks Specific to the Canadian Segment” for additional risks specific to competition in the Canadian beer market.
Competition in our markets could require us to reduce prices or increase capital and other expenditures or cause us to lose sales volume, any of which could have a material adverse effect on our business and financial results. In many of our markets, our primary competitors have greater financial, marketing, production and distribution resources than we do, and may be more diverse in terms of their geographies and brand portfolios. In all of the markets in which we operate, aggressive marketing strategies, such as reduced pricing, brand positioning, and increased capital or other investments by these competitors could have a material adverse effect on our business and financial results. In addition, continuing consolidation among major global brewers and between brewers and other beverage companies may lead to stronger or new competitors, loss of partner brands, negative impacts on our distributor networks and pressures from marketing and pricing tactics by competitors. Further, consolidation of distributors in our industry could reduce our ability to promote our brands in the market in a manner that enhances rather than diminishes their value, as well as reduce our ability to manage our pricing effectively. Additionally, due to competition with brewers and other beverage companies, an increase in the purchasing power of our large competitors may cause further pricing pressures which could prevent us from increasing prices to recover higher costs necessary to compete. Such pressures could have a material adverse impact on our business and our financial results and market share. Failure to generate significant cost savings and margin improvement through our ongoing initiatives could adversely affect our profitability. Increased pressures for reduced pricing or difficulties in increasing prices while remaining competitive within our markets, as well as the need for increased capital investment, marketing and other expenditures could result in lower margins or loss of market share and volumes. Moreover, most of our major markets are mature, so growth opportunities may be more limited to us than to our competitors. For example, sales in the U.S. and Canada accounted for approximately 80% of our total 2018 sales.
Our success as an enterprise depends largely on the success of relatively few products in several mature markets specific to the beer industry; if consumer preferences shift away from our products or consumption of our products decline, our business and financial results could be materially adversely affected. Our Coors Light and Miller Lite brands in the U.S., Coors Light, Molson Canadian , Coors Banquet and Carling brands in Canada, and Carling, Staropramen, Jelen, Bergenbier and Coors Light brands in Europe represented approximately half of each respective segment's sales volumes in 2018. Additionally, several of our brands represent a significant share of their respective market, therefore volatility in these markets could disproportionately impact the performance of these brands. Consequently, any material shift in consumer preferences away from these brands, or from the categories in which they compete, could have a material adverse effect on our business and financial results. Consumer preferences and tastes may shift away from our brands or beer generally due to, among others, changing taste preferences, demographics, downturn in economic conditions or perceived value, as well as changes in consumers' perception of our brands due to negative publicity, regulatory actions or litigation. Recently, there has been more attention focused on health concerns and the harmful effects of alcoholic beverages which could result in a change in the social acceptability of beer and other alcoholic beverages which could materially impact the consumption of beer and our sales. Additionally, in some of our major markets, specifically Canada, the U.S. and Europe, there has been a shift in consumer preferences within the total beer market away from premium brands to "craft beer" produced by smaller, regional microbreweries, as well as a shift within the total alcohol beverage market from beer to wine and spirits. Moreover, several of our major markets are mature and we have a significant share in such markets, therefore, small movements in consumer preference, such as consumer shifts away from premium light brands, can disproportionately impact our results. Although the ultimate impact is currently unknown, the emergence of legal cannabis in certain U.S. states and Canada may result in a shift of discretionary income away from our products or a change in consumer preferences away from beer. As a result, a shift in consumer preferences away from our products or beer or a decline in the consumption of our products could result in a material adverse effect on our business and financial results.
The success of our business relies heavily on brand image, reputation, product quality and protection of intellectual property. It is important that we maintain and increase the image and reputation of our existing brands and products. Concerns about product quality, even when unsubstantiated, could be harmful to our image and reputation of our brands and products. While we have quality control programs in place, in the event we experienced an issue with product quality, we may experience recalls or liability in addition to business disruption which could further negatively impact brand image and reputation and negatively affect our sales. Our brand image and reputation may also be more difficult to protect due to less oversight and control as a result of the outsourcing of some of our operations. We also could be exposed to lawsuits relating to product liability or marketing or sales practices. Deterioration to our brand equity may be difficult to combat or reverse and could have a material effect on our business and financial results. In addition, because our brands carry family names, personal activities by certain members of the Molson or Coors families that harm their public image or reputation could have an adverse effect on our brands. Further, our success is dependent on our ability to protect our intellectual property rights, including trademarks, patents, domain names, trade secrets and know-how. We cannot be certain that the steps we have taken to protect
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billion to goodwill and indefinite-lived intangible assets, respectively. These assets are tested for impairment at least annually, using estimates and assumptions affected by factors such as economic and industry conditions and changes in operating performance. Additionally, in conjunction with the brand impairment tests, we also reassess each brand's indefinite-life classification. Potential resulting charges from an impairment of goodwill or brand intangible, as well as reclassification of an indefinite-lived to a definite-lived brand intangible, could have a material adverse effect on our results of operations. For example, the results of our annual impairment testing completed as of October 1, 2016, indicated that the fair value of the Molson core brand indefinite-lived intangible asset was below its carrying value. As a result, we recorded an impairment charge of $495.2 million recorded within special items in our consolidated statements of operations during the fourth quarter of 2016. Additionally, during this review, we also reassessed the asset’s indefinite-life classification and determined that the Molson core brands have characteristics that have evolved which now indicate a definite-life is more appropriate. These brands were therefore reclassified as definite-lived intangible assets and are being amortized over useful lives ranging from 30 to 50 years.
Our most recent impairment analysis, conducted as of October 1, 2018, the first day of our fiscal fourth quarter, indicated that the fair value of the U.S., Europe and Canada reporting units were estimated at approximately 19%, 11% and 6% in excess of their carrying values, respectively. In the current year testing, it was determined that the fair value of each of the reporting units declined from the prior year, resulting in our Europe and Canada reporting units now being considered at risk of future impairment in the event of significant unfavorable changes in the forecasted cash flows (including prolonged weakening of economic conditions, or significant unfavorable changes in tax, environmental or other regulations, including interpretations thereof), terminal growth rates, market multiples and/or weighted-average cost of capital utilized in the discounted cash flow analyses. Although the fair values of our reporting units are in excess of their carrying values, the fair values are sensitive to the aforementioned potential unfavorable changes that could have an adverse impact on future analyses. Any future impairment of the U.S., Europe or Canada reporting units or brands, or reclassification of indefinite-lived brands to definite-lived, may result in material charges that could have a material adverse effect on our business and financial results. Additionally, if the on-going integration of the MillerCoors and Miller International Business is unsuccessful due to, for example, unexpected challenges or difficulties, or adverse economic, market or industry conditions, material impairment charges may be incurred in the future. The testing of our goodwill for impairment is predicated upon our determination of our reporting units. Any change to the conclusion of our reporting units or the aggregation of components within our reporting units could result in a different outcome to our annual impairment test. See Part II-Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Estimates and Part II-Item 8 Financial Statements and Supplementary Data, Note 10, "Goodwill and Intangible Assets" of the Notes for additional information related to the results of our annual impairment testing.
Termination of one or more manufacturer/distribution agreements could have a material adverse effect on our business and financial results. We manufacture and/or distribute products of other beverage companies through various joint venture, licensing, distribution, contract brewing or other similar arrangements, such as our agreement to import, market, distribute and sell Heineken in Canada and our arrangements to brew and distribute Beck's, Stella Artois, Lowenbrau and Spaten and to distribute Corona in Central Europe. Our inability to renew or the loss of one or more of these arrangements, as a result of industry consolidation or otherwise, could have a material adverse effect on our business and financial results. For example, in 2017, our International segment was adversely impacted by the loss of the Modelo brands in Japan.
Changes in various supply chain standards or agreements could have a material adverse effect on our business and financial results. Our business includes various joint venture and industry agreements which standardize parts of the supply chain system. An example includes our warehousing and customer delivery systems in Canada organized under joint venture agreements with other brewers. Any negative change in these agreements or material terms within these agreements could have a material adverse effect on our business and financial results.
We rely on a small number of suppliers to obtain the packaging materials we need to operate our business. The inability to obtain materials could unfavorably affect our ability to produce our products which could have a material adverse effect on our business and financial results. We purchase certain types of packaging materials including aluminum cans and bottles, glass bottles and paperboard from a small number of suppliers. Consolidation of packaging materials suppliers has reduced local supply alternatives and increased risks of supply disruptions. The inability of any of these suppliers to meet our production requirements without sufficient time to develop an alternative source could have a material adverse effect on our business and financial results. Additionally, if the financial condition of these suppliers deteriorates our business and financial results could be adversely impacted. Our suppliers’ financial condition is affected in large part by conditions and events that are beyond our and their control, including: competitive and general market conditions in the locations in which they operate; the availability of capital and other financing resources on reasonable terms; loss of major customers; or disruptions of bottling operations that may be caused by strikes, work stoppages, labor unrest or natural disasters. A deterioration of the financial condition or results of operations of one or more of our major suppliers could adversely affect our business and financial results.
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Concern over climate change may result in new or increased regional, federal and global legal and regulatory requirements to reduce or mitigate the effects of greenhouse gases, or to limit or impose additional costs on commercial water use due to local water scarcity concerns. In the event that such regulation is more stringent than current regulatory obligations or the measures that we are currently undertaking to monitor and improve our energy efficiency and water conservation, we may experience disruptions in, or increases in our costs of, operation and delivery and we may be required to make additional investments in facilities and equipment or relocate our facilities. In particular, increasing regulation of fuel emissions could increase the cost of energy, including fuel, required to operate our facilities or transport and distribute our products, thereby increasing the distribution and supply chain costs associated with our products. As a result, the effects of climate change or water scarcity could negatively affect our business and operations. In addition, any failure to achieve our goals with respect to reducing our impact on the environment or perception (whether or not valid) of our failure to act responsibly with respect to water use and the environment or to effectively respond to new, or changes in, legal or regulatory requirements concerning climate change or water scarcity could result in adverse publicity and could adversely affect our business, reputation, financial condition or results of operations. There is also increased focus, including by governmental and non- governmental organizations, investors, customers and consumers on these and other environmental sustainability matters, including deforestation, land use, climate impact and water use. Our reputation could be damaged if we or others in our industry do not act, or are perceived not to act, responsibly with respect to our impact on the environment.
Loss or closure of a major brewery or other key facility, due to unforeseen or catastrophic events or otherwise, could have a material adverse effect on our business and financial results. Our business could be interrupted and our financial results could be materially adversely impacted by physical risks such as earthquakes, hurricanes, floods, terror attacks and other natural disasters or catastrophic events that damage or destroy one of our breweries or key facilities or the key facilities of our significant suppliers. Additionally, certain catastrophes are not covered by our general insurance policies, which could result in significant unrecoverable losses. Furthermore, our business and results of operations could be adversely impacted by under-investment in physical assets or production capacity, including contract brewing and effect on priority of our brands if production capacity is limited. Further, significant excess capacity at any of our breweries as a result of increased efficiencies in our supply chain process or continued volume declines, could result in under-utilization of our assets, which could lead to excess overhead expenses or additional costs incurred associated with the closure of one or more of our facilities. For example, as part of a strategic review of our supply chain network, certain breweries and bottling lines were closed in recent years, and we have and continue to incur brewery closure costs. We regularly review our supply chain network to ensure that our supply chain capacity is aligned with the needs of the business. Such reviews could potentially result in further closures and the related costs could be material.
Failure to successfully identify, complete or integrate attractive acquisitions and joint ventures into our existing operations could have an adverse effect on our business and financial results. We have made a number of acquisitions and entered into several strategic joint ventures. In order to compete in the consolidating global brewing industry, we anticipate that we may, from time to time, in the future acquire additional businesses or enter into additional joint ventures that we believe would provide a strategic fit with our business such as the Acquisition and our Canadian business' joint venture with HEXO. Potential risks associated with acquisitions and joint ventures could include, among other things: our ability to identify attractive acquisitions and joint ventures; our ability to offer potential acquisition targets and joint venture partners' competitive transaction terms; our ability to raise capital on reasonable terms to finance attractive acquisitions and joint ventures; our ability to realize the benefits or cost savings that we expect to realize as a result of the acquisition or joint venture; diversion of management's attention; our ability to successfully integrate our businesses with the business of the acquired company; motivating, recruiting and retaining key employees; conforming standards, controls, procedures and policies, business cultures and compensation structures among our company and the acquired company; consolidating and streamlining sales, marketing and corporate operations; potential exposure to unknown liabilities of acquired companies; potential exposure to unknown or future liabilities or costs that affect the markets in which acquired companies or joint ventures operate; reputational or other damage due to the conduct of a joint venture partner; loss of key employees and customers of the acquired business; and managing tax costs or inefficiencies associated with integrating our operations following completion of an acquisition or entry into a joint venture.
Poor investment performance of pension plan holdings and other factors impacting pension plan costs could unfavorably affect our business, liquidity and our financial results. Our costs of providing defined benefit pension plans are dependent upon a number of factors, such as the rates of return on the plans' assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, exchange rate fluctuations, government regulation, court rulings or other changes in legal requirements, global equity prices, and our required and/or voluntary contributions to the plans. While we comply with the minimum funding requirements, we have certain qualified pension plans with obligations which exceed the value of the plans' assets. These funding requirements also may require contributions even when there is no reported deficit. Without sustained growth in the pension investments over time to increase the value of the plans' assets, and depending upon the other factors as listed above, we could be required to fund the plans with significant amounts of cash. Such
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cash funding obligations (or the timing of such contributions) could have a material adverse effect on our cash flows, credit rating, cost of borrowing, financial position and/or results of operations. For example, following the completion of the triennial review of the U.K. pension plan with the plan's trustees in 2014, we made a GBP 150 million contribution to our U.K. pension plan in January 2015, based on the underfunded status of the plan and the evaluation of the plan's performance and long-term obligations. In addition, we made pension plan contributions during 2017 of approximately $310 million, including $200 million of discretionary contributions to the U.S. pension plan.
We depend on key personnel, the loss of whom could harm our business. The loss of the services and expertise of any key employee could harm our business. Our future success depends on our ability to identify, attract and retain qualified personnel on a timely basis. Turnover of senior management can adversely impact our stock price, our results of operations and our client relationships and may make recruiting for future management positions more difficult. In addition, we must successfully integrate any new management personnel that we hire within our organization, or who join our organization as a result of an acquisition, in order to achieve our operating objectives, and changes in other key management positions may temporarily affect our financial performance and results of operations as new management becomes familiar with our business.
Due to a high concentration of workers represented by unions or trade councils in Canada, Europe, and the U.S., we could be significantly affected by labor strikes, work stoppages or other employee-related issues. As of December 31, 2018, approximately 50%, 35%, and 30% of our Canadian, European and U.S. workforces, respectively, are represented by trade unions or councils. Stringent labor laws in certain of our key markets expose us to a greater risk of loss should we experience labor disruptions in those markets. A prolonged labor strike, work stoppage or other employee-related issue, could have a material adverse effect on our business and financial results. For example, in the first quarter of 2017, our Toronto brewery unionized employees commenced a labor strike initiated from on-going negotiations of the collective bargaining agreement. This labor strike resulted in slower than expected production at the Toronto brewery in the first quarter of 2017. From time to time, our collective bargaining agreements come due for renegotiation, and, if we are unable to timely complete negotiations, affected employees may strike, which could have an adverse effect on our business and financial results.
Because of our reliance on third-party service providers and internal and outsourced systems for our information technology and certain other administrative functions, we could experience a disruption to our business. We rely extensively on information services providers worldwide for our information technology functions including network, help desk, hardware and software configuration. Additionally, we rely on internal networks and information systems and other technology, including the internet and third-party hosted services, to support a variety of business processes and activities, including procurement and supply chain, manufacturing, distribution, invoicing and collection of payments. We use information systems for certain human resource activities and to process our employee benefits, as well as to process financial information for internal and external reporting purposes and to comply with various reporting, legal and tax requirements. As information systems are critical to many of our operating activities, our business may be impacted by system shutdowns, service disruptions, obsolescence, or security breaches. Additionally, if one of our service providers were to fail and we were unable to find a suitable replacement in a timely manner, we could be unable to properly administer our outsourced functions.
A breach of our information systems could cause material financial or reputational harm. Our internal and outsourced systems may also be the target of cyber-attacks or other breaches to our security, which, if successful, could expose us to the loss of key business, employee, customer or vendor information and disruption of our operations. If our information systems suffer severe damage, disruption or shutdown, we could experience delays in reporting our financial results and we may lose revenue and profits as a result of our inability to timely prepare, distribute, invoice and collect payments from our customers. Misuse, leakage or falsification of information could result in a violation of data privacy laws and regulations, such as the European Union's General Data Protection Regulation, or damage our reputation and credibility. In addition, we may suffer financial and reputational damage because of lost or misappropriated confidential information and may become subject to legal action and increased regulatory oversight or consumers may avoid our brands due to negative publicity. We could also be required to spend significant financial and other resources to remedy the damage caused by a security breach or to repair or replace networks and information systems, which could have a material adverse effect on our business and financial results.
If the Pentland Trust and the Coors Trust do not agree on a matter submitted to our stockholders or if a super-majority of our board of directors do not agree on certain actions, generally the matter will not be approved, even if beneficial to us or favored by other stockholders or a majority of our board of directors. Pentland Securities (1981) Inc. (the "Pentland Trust") (a company controlled by the Molson family and related parties) and the Adolph Coors, Jr. Trust (the "Coors Trust"), which together control more than 90% of our Class A common stock and Class A exchangeable shares, have a voting trust agreement through which they have combined their voting power over the shares of our Class A common stock and the Class A exchangeable shares that they own. If these two stockholders do not agree to vote in favor of a matter submitted to a stockholder vote (other than the election of directors), the voting trustees are required to vote all of the Class A common stock
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• failure to develop sustainable production sources prior to the expiration of ABI's production services.
We may not be able to maintain the levels of revenue, earnings or operating efficiency that each of the Company and the Miller International Business had achieved or might achieve separately. The markets in which the Miller International Business operates may not experience the growth rates expected and any economic downturn affecting those markets could negatively impact the Miller International Business. These markets are in differing stages of development and may experience more volatility than expected or face more operating risks than in the more mature markets in which we have historically operated. If the Miller International Business or the markets in which it operates deteriorate, the potential cost savings, growth opportunities and other synergies of the acquisition of the Miller International Business may not be realized fully, or at all, or may take longer to realize than expected. In such case, our business, financial condition, results of operations and cash flows may be negatively impacted.
We have identified a material weakness in our internal control over financial reporting which, if not remediated, could adversely affect our business, reputation and stock price. As part of preparing our 2018 consolidated financial statements, we identified errors in the accounting for income taxes related to the deferred tax liabilities for our partnership in MillerCoors. See Part II-Item 8 Financial Statements and Supplementary Data, Note 1, "Basis of Presentation and Summary of Significant Accounting Policies" for further discussion.
As a result of these errors, management identified a material weakness in internal control over financial reporting as of December 31, 2018, related to designing and maintaining effective controls over the completeness and accuracy of the accounting for, and disclosure of, the income tax effects of acquired partnership interests. Specifically, we did not design appropriate controls to identify and reconcile deferred income taxes associated with the accounting for acquired partnership interests. This material weakness resulted in material errors in connection with our step acquisition of MillerCoors that were corrected through the restatement of the consolidated financial statements as of and for the years ended December 31, 2017, and December 31, 2016, as described in Part II-Item 8 Financial Statements and Supplementary Data, Note 1, "Basis of Presentation and Summary of Significant Accounting Policies" to the consolidated financial statements and the correction of the unaudited quarterly financial information for fiscal years 2018 and 2017. Additionally, this material weakness could result in misstatements to the aforementioned account balances or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. As a result of the material weakness in internal control over financial reporting, management has concluded that we did not maintain effective internal control over financial reporting as of December 31, 2018, based on criteria set forth by the Committee of Sponsoring Organization of the Treadway Commission in “ Internal Control-An Integrated Framework (2013).” We cannot assure you that we will not identify additional material weaknesses in our internal control over financial reporting in the future related to income tax or other controls. If the steps we take do not correct the material weakness in a timely manner, we may be unable to conclude in the future that we maintain effective internal control over financial reporting. The occurrence of or failure to remediate this or future material weaknesses may adversely affect our reputation and business and the market price of our common stock.
## Risks Specific to the United States Segment
Our U.S. business is highly dependent on independent distributors to sell our products, with no assurance that these distributors will effectively sell our products. We sell nearly all of our products, including all of our imported products, in the U.S. to independent distributors for resale to retail outlets. These independent distributors are entitled to exclusive territories and protected from termination by state statutes and regulations. Consequently, if we are not allowed, or are unable under acceptable terms or at all, to replace unproductive or inefficient distributors, our business, financial position and results of operation may be adversely affected, which could have a material adverse effect on our business and financial results.
## Risks Specific to the Canada Segment
Our Canadian business faces numerous risks relating to its joint venture in the Canadian cannabis industry. On October 4, 2018, a wholly-owned subsidiary within our Canadian business completed the formation of an independent Canadian joint venture with HEXO, a Canadian entity listed on the Toronto Stock Exchange that serves the Canadian cannabis market. The joint venture, Truss LP, will pursue opportunities to develop non-alcoholic, cannabis-infused beverages for the Canadian market following legalization. The success and consumer acceptance of any products produced by the joint venture cannot be assured. Further, our Canadian subsidiary’s involvement in the Canadian cannabis industry may negatively impact: consumer, business partner, investor or public sentiment regarding our brands, Canadian beer business or our company. The emerging cannabis industry in Canada and in other jurisdictions is evolving rapidly and subjects us to a high degree of political, legal and regulatory uncertainty, including when and if regulations in Canada will ultimately be adopted that would allow the
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## Cautionary Statement Pursuant to Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995
This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, (the "Exchange Act"). From time to time, we may also provide oral or written forward-looking statements in other materials we release to the public. Such forward-looking statements are subject to the safe harbor created by the Private Securities Litigation Reform Act of 1995.
Statements that refer to projections of our future financial performance, our anticipated growth and trends in our businesses, and other characterizations of future events or circumstances are forward-looking statements, and include, but are not limited to, statements in Part II— Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations in this report, and under the heading "Outlook for 2019" therein, overall volume trends, consumer preferences, pricing trends, industry forces, cost reduction strategies, anticipated results, anticipated synergies, expectations for funding future capital expenditures and operations, expectations regarding future dividends, debt service capabilities, timing and amounts of debt and leverage levels, shipment levels and profitability, market share and the sufficiency of capital resources. In addition, statements that we make in this report that are not statements of historical fact may also be forward-looking statements. Words such as "expects," "goals," "plans," "believes," "continues," "may," "anticipate," "seek," "estimate," "outlook," "trends," "future benefits," "potential," "projects," "strategies," and variations of such words and similar expressions are intended to identify forward-looking statements.
Forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those indicated (both favorably and unfavorably). These risks and uncertainties include, but are not limited to, those described in Part I—Item 1A "Risk Factors" elsewhere throughout this report, and those described from time to time in our past and future reports filed with the SEC. Caution should be taken not to place undue reliance on any such forward-looking statements. Forward-looking statements speak only as of the date when made and we undertake no obligation to update any forward-looking statement, whether as a result of new information, future events or otherwise.
## Market and Industry Data
The market and industry data used in this Annual Report on Form 10-K are based on independent industry publications, customers, trade or business organizations, reports by market research firms and other published statistical information from third parties, as well as information based on management’s good faith estimates, which we derive from our review of internal information and independent sources. Although we believe these sources to be reliable, we have not independently verified the accuracy or completeness of the information.
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Effective in the first quarter of 2018, we have revised our net sales per hectoliter performance discussions to include a brand volume basis as defined above (with the exception of the STW to STR adjustment) with the net sales revenue component reflecting owned and actively managed brands as well as royalty revenue consistent with how management views the business. We continue to also discuss net sales per hectoliter performance on a reported basis.
<img src='content_image/1054346.jpg'>
Our worldwide brand volume decreased in 2018 compared to 2017, due to declines in the U.S. and Canada, partially offset by growth in Europe and International. Worldwide brand volume increased in 2017 compared to 2016, due to the Acquisition as well as strong growth in Europe and International partially as a result of adding the Miller global brands business as well as growth within our existing brand portfolio.
## Net Sales Drivers
The following table highlights the drivers of change in net sales for the year ended December 31, 2018, versus December 31, 2017, by segment (in percentages) and excludes Corporate net sales revenue for our water resources and energy operations in the state of Colorado.
<img src='content_image/1054345.jpg'>
(1) Includes the impacts of the adoption of the new accounting pronouncement related to revenue recognition as discussed above. See Part II— Item 8 Financial Statements and Supplementary Data, Note 1, "Basis of Presentation and Summary of Significant Accounting Policies" and Note 2, "New Accounting Pronouncements " for further discussion on the adoption of this revenue recognition guidance.
(2) Europe "Other" column includes the impacts of the release of an indirect tax provision in 2017 as further described in the Results of Operations.
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The following represents our proportionate share of MillerCoors' net income reported under the equity method prior to the Acquisition:
<img src='content_image/1023876.jpg'>
(1) See Part II—Item 8 Financial Statements and Supplementary Data, Note 4, "Acquisition and Investments" of the Notes, for a detailed discussion of these equity method adjustments prior to the Acquisition.
The discussion below highlights the U.S. segment results of operations for the year ended December 31, 2018, versus the year ended December 31, 2017, and for the year ended December 31, 2017, versus the year ended December 31, 2016, on a reported and pro forma basis, where applicable.
## Significant events
Throughout 2018, U.S. financial volume, including shipment timing and distributor inventory levels, as well as financial results were impacted by brewery system implementations at our Golden, Colorado, Trenton, Ohio and Fort Worth, Texas breweries. We continue to prepare for future implementations at our remaining breweries expected to occur in 2019, including the implementation at our Milwaukee, Wisconsin brewery, which is currently underway.
In order to align our cost base with our scale of business, during the third quarter of 2018, we initiated restructuring activities in the U.S. and reduced U.S. employment levels by approximately 300 employees in the fourth quarter of 2018. As a result, severance costs related to these restructuring activities were recorded as special charges.
The volatility of aluminum, inclusive of Midwest Premium, and freight and fuel costs continued to significantly impact our results during 2018. To the extent these prices continue to fluctuate, our business and financial results could be materially adversely impacted. We continue to monitor these risks and rely on our risk management hedging program to help mitigate price risk exposure for commodities including aluminum and fuel.
In order to increase overall operating efficiency, during the first quarter of 2018, the U.S. segment announced plans to close the Colfax, California cidery. The cidery closed in January 2019 and cider production has moved to the 10th Street Brewery in Milwaukee, Wisconsin. We recognized special charges in 2018 associated with the cidery closure consisting primarily of accelerated depreciation in excess of normal depreciation.
On October 11, 2016, we completed the Acquisition and as a result, MCBC owns 100% of the outstanding equity and voting interests of MillerCoors. Therefore, beginning October 11, 2016, MillerCoors' results of operations have been prospectively consolidated into MCBC’s consolidated financial statements and included in the U.S. segment. See Part II—Item 8 Financial Statements and Supplementary Data, Note 4, "Acquisition and Investments" for further details. Additionally, effective January 1, 2017, the results of the MillerCoors Puerto Rico business, which were previously included as part of the U.S. segment, are now reported within the International segment. Note, we only present unaudited pro forma financial information for the consolidated entity and the U.S. segment.
During the third quarter of 2015, the U.S. business announced plans to close its brewery in Eden, North Carolina in an effort to optimize the brewery footprint and streamline operations for greater efficiencies. Products produced in Eden were transitioned to other breweries in the U.S. supply chain network and the Eden brewery is now closed. Total special charges
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[
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overall_image/cb587b97c39d329848c65f61f220b24399fc9f013955c5ad02a59fdae030ba19.png
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## International Segment
<img src='content_image/1020549.jpg'>
N/M = Not meaningful
(1) Financial volumes for the year ended December 31, 2016, were recast to reflect the impacts of aligning policies on reporting financial volumes as a result of the Acquisition.
(2) Excludes royalty volume of 2.267 million hectoliters, 1.991 million hectoliters and 1.908 million hectoliters in 2018, 2017 and 2016, respectively.
(3) Includes gross inter-segment purchases, which are eliminated in the consolidated totals.
(4) See Part II—Item 8 Financial Statements and Supplementary Data, Note 7, "Special Items" of the Notes for detail of special items.
## Significant events
During the first half of 2018, we decided to formally exit our business in China and, as such, have incurred special charges. See Part II—Item 8 Financial Statements and Supplementary Data, Note 7, "Special Items" of the Notes for further detail.
As a result of the Acquisition, the Miller brands were added to our International segment's portfolio beginning October 11, 2016. Additionally, as a result of the Acquisition, effective January 1, 2017, European markets including Sweden, Spain, Germany, Ukraine and Russia, which were previously reported as part of our International segment, are reported within our Europe segment while the results of the MillerCoors Puerto Rico business, which were previously included as part of the U.S. segment, are reported within the International segment.
On April 5, 2016, the government of the state of Bihar implemented a complete prohibition of the sale and consumption of all forms of alcohol. As a result of this ban, our Molson Coors Cobra India business is currently not operating. This ban does not impact the rest of our business in India outside of the state of Bihar. As a result, we recorded an aggregate impairment charge of $30.8 million within special items during the second quarter of 2016. We continue to monitor legal proceedings impacting the regulatory environment as it relates to our ability to resume operations in the state.
## Foreign currency impact on results
Our International segment operates in numerous countries around the world and each country's operations utilize distinct currencies. Foreign currency movements unfavorably impacted our International USD loss before income taxes by $3.2 million for 2018 and favorably impacted our International USD loss before income taxes by $0.2 million for 2017. Included in these amounts are both translational and transactional impacts of changes in foreign exchange rates. The impact of transactional foreign currency gains and losses is recorded within other income (expense) in our consolidated statements of operations.
## Volume and net sales
Our International brand volume increased 2.2% in 2018 compared to 2017, driven by organic volume growth in many of our focus markets, partially offset by lower volumes in Mexico due to higher net pricing and the loss of the Modelo contract in
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Japan at the end of the second quarter of 2017. Our International financial volume decreased 7.5% in 2018 compared to 2017, driven by shifting to local third party production in Mexico, which increased our royalty volume.
Net sales per hectoliter on a brand volume basis decreased 7.3% in 2018 compared to 2017, primarily driven by sales mix changes and shifting to local production in Mexico, partially offset by positive net pricing. Net sales per hectoliter on a reported basis increased 2.4% in 2018 compared to 2017 due to changes in sales mix.
Brand volume increased 28.9% in 2017 compared to 2016, driven by the change in segment reporting of the Puerto Rico business from the U.S. segment, Coors Light growth primarily in Latin America and the addition of the Miller brands partially offset by the transfer of royalty and export brand volume to Europe.
Net sales per hectoliter on a brand volume basis increased 25.2% in 2017 compared to 2016, primarily due to sales mix changes and positive pricing. Net sales per hectoliter on a reported basis increased 0.8% in 2017 compared to 2016, driven by positive net pricing and favorable sales mix.
## Cost of goods sold
Cost of goods sold per hectoliter decreased 3.9% in 2018 compared to 2017, primarily driven by sales mix changes. Additionally, during 2018 we recorded $1.0 million of integration costs related to the Acquisition within cost of goods sold.
Cost of goods sold per hectoliter increased 5.2% in 2017 compared to 2016, primarily driven by sales mix changes. Additionally, during 2017 we recorded $3.6 million of integration costs related to the Acquisition within cost of goods sold.
## Marketing, general and administrative expenses
Marketing, general and administrative expenses decreased 19.8% in 2018 compared to 2017, primarily due to lower marketing investments, overhead, and integration costs as well as $2.0 million of settlement proceeds related to our Colombia business in the first quarter of 2018. During 2018, we recorded $1.8 million of integration costs related to the Acquisition within marketing, general and administrative expenses.
Marketing, general and administrative expenses increased 56.0% in 2017 compared to 2016, primarily due to higher organization and integration costs related to the acquisition of the Miller global brands, along with increased brand investments, including higher brand amortization costs. During 2017, we recorded $8.4 million of integration costs related to the Acquisition within marketing, general and administrative expenses.
## Corporate Segment
<img src='content_image/1056776.jpg'>
N/M = Not meaningful
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67,615
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A significant portion of our cash flows from operating activities is generated outside the U.S., in currencies other than USD. As of December 31, 2018, approximately 47% of our cash and cash equivalents were located outside the U.S., largely denominated in foreign currencies. We accrue for tax consequences on the earnings of our foreign subsidiaries upon repatriation. When the earnings are considered indefinitely reinvested outside of the U.S., we do not accrue taxes. However, we continue to assess the impact of the 2017 Tax Act on the tax consequences of future repatriations. We utilize a variety of tax planning and financing strategies in an effort to ensure that our worldwide cash is available in the locations in which it is needed. We periodically review and evaluate these strategies, including external committed and non-committed credit agreements accessible by MCBC and each of our operating subsidiaries. We believe these financing arrangements, along with the cash generated from the operations of our U.S. segment, are sufficient to fund our current cash needs in the U.S.
## Cash Flows and Use of Cash
Our business generates positive operating cash flow each year, and our debt maturities are of a longer-term nature. However, our liquidity could be impacted significantly by the risk factors described in Part I, Item 1A. Risk Factors.
## Cash Flows from Operating activities
Net cash provided by operating activities of approximately $2.3 billion in 2018, increased by $465.0 million compared to 2017. This increase was driven by the proceeds received during the first quarter of $328.0 million related to the Adjustment Amount as defined and further discussed in Part II—Item 8 Financial Statements and Supplementary Data, Note 4, "Acquisition and Investments" of the Notes, lower pension contributions and interest paid, partially offset by unfavorable changes in working capital and lower cash tax receipts.
Net cash provided by operating activities of approximately $1.9 billion in 2017 increased by $739.4 million compared to 2016. This increase is primarily related to the addition of the consolidated U.S. business, lower cash paid for taxes (refund in 2017 as compared to cash tax paid in 2016) and working capital improvements, partially offset by higher pension contributions including the discretionary cash contribution of $200 million to the U.S. pension plan and higher cash paid for interest.
## Cash Flows from Investing activities
Net cash used in investing activities of $669.1 million in 2018, increased by $130.9 million compared to 2017 primarily due to higher capital expenditures, increased outflows from other investing activities, including acquisitions, as well as lower proceeds related to asset disposals.
Net cash used in investing activities of $538.2 million in 2017 decreased by approximately $11.7 billion compared to 2016 driven primarily by the completion of the Acquisition in 2016 for $12.0 billion, offset by higher capital expenditures in 2017 resulting from the Acquisition.
## Cash Flows from Financing activities
Net cash used in financing activities of approximately $1.0 billion in 2018, decreased by $487.5 million from net cash used in financing activities of approximately $1.5 billion in 2017. This decrease was primarily driven by lower net repayments on debt and borrowings in 2018 compared to 2017, partially offset by the repayment of borrowings under our commercial paper program in 2018 compared to an increase in borrowings under our commercial paper program in the prior year.
Net cash used in financing activities of approximately $1.5 billion in 2017, decreased by approximately $12.8 billion from net cash provided by financing activities of approximately $11.3 billion in 2016. This change was primarily driven by the approximate $2.5 billion of net proceeds received from our February 3, 2016, equity offering of 29.9 million shares of our Class B common stock, the approximate $6.9 billion of net proceeds from the issuance of debt on July 7, 2016, to partially fund the Acquisition in 2016, as well as increased net repayments of debt as we began to deleverage in 2017. See "Borrowings" below for more details on financing activity.
See Part II—Item 8 Financial Statements and Supplementary Data, Note 11, "Debt" of the Notes for a summary of our financing activities and debt position as of December 31, 2018, and December 31, 2017.
## Capital Resources
## Cash and Cash Equivalents
As of December 31, 2018, we had total cash and cash equivalents of approximately $1.1 billion, compared to $418.6 million as of December 31, 2017. The increase in cash and cash equivalents as of December 31, 2018, from December 31, 2017, was primarily driven by the net proceeds from operating activities including the proceeds received during the first quarter of $328.0 million related to the Adjustment Amount as defined and further discussed in Part II—Item 8 Financial Statements and Supplementary Data, Note 4, "Acquisition and Investments" of the Notes, partially offset by repayments of borrowings,
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capital expenditures and dividend payments. The majority of our cash and cash equivalents are invested in a variety of highly liquid investments with original maturities of 90 days or less. These investments are viewed by management as low-risk investments on which there are little to no restrictions regarding our ability to access the underlying cash to fund our operations as necessary. While we have some investments in prime money market funds, these are classified as cash and cash equivalents; however, we continually monitor the need for reclassification under the updated SEC requirements for money market funds, and the potential that the shares of such funds could have a net asset value of less than one dollar. We also utilize cash pooling arrangements to facilitate the access to cash across our geographies.
## Working Capital
The Company actively manages working capital through inventory management as well as management of accounts payable and accounts receivable to ensure we are able to meet short-term obligations and we are effectively using assets to increase profitability.
## Borrowings
During the third quarter of 2018, we repaid our CAD 400 million 2.25% notes which matured in September 2018. Notional amounts are presented in USD based on the applicable exchange rate as of December 31, 2018. Refer to Part II—Item 8 Financial Statements and Supplementary Data, Note 11, "Debt" for details regarding the cross currency swaps on our $500 million 2.25% senior notes due 2020 which economically converted these notes to EUR denominated.
<img src='content_image/1024317.jpg'>
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## Guarantees
We guarantee indebtedness and other obligations to banks and other third parties for some of our equity method investments and consolidated subsidiaries. See Part II—Item 8 Financial Statements and Supplementary Data, Note 18, "Commitments and Contingencies" of the Notes for further discussion.
## Other Commercial Commitments
Based on foreign exchange rates as of December 31, 2018, future commercial commitments are as follows:
<img src='content_image/1037247.jpg'>
## Contingencies
We are party to various legal proceedings arising in the ordinary course of business, environmental litigation and indemnities associated with our sale of Kaiser to FEMSA. See Part II—Item 8 Financial Statements and Supplementary Data, Note 18, "Commitments and Contingencies" of the Notes for further discussion.
## Off-Balance Sheet Arrangements
In accordance with U.S. GAAP, our operating leases are not reflected in our consolidated balance sheets. See Part II—Item 8 Financial Statements, Note 18, "Commitments and Contingencies" of the Notes for further discussion of these off-balance sheet arrangements. As of December 31, 2018, we did not have any other material off-balance sheet arrangements (as defined in Item 303(a)(4)(ii) of Regulation S-K).
## Outlook for 2019
In the U.S., Miller Lite continues its strong segment trend while Coors Light’s relative performance improved with the brand holding share of segment in the fourth quarter of 2018. In 2019, we have plans to accelerate our above premium portfolio through higher investment. We plan to double our media spend on Blue Moon , the number one national craft brand, air national advertising for Peroni for the first time, build on a very successful year-one for both Arnold Palmer Spiked Half and Half and Sol , increase the presence of Henry's Hard in the fast growing hard seltzer category, focusing on the brand's clear product differentiators of zero sugar and only 88 calories and introduce a number of innovations, including Cape Line , Saint Archer Gold , Crispin extensions and Sol Chelada - all before this summer. Our U.S. business enters 2019 having further strengthened its position as the trusted category captain across chain accounts in both the off- and on-premise channels and more broadly our customer excellence performance is market leading and improving further, as evidenced by the Advantage Survey results. Additionally, allied to this we have ramped up our e-commerce approach within joint business plans and continue to build competitive advantage through our technology enabled field sales teams with tools such as BeerMate, which we are rolling out globally. Our new Coors Light advertising is now on air, and we believe we are moving in the right direction with the brand, allowing us to take even more share in premium lights. We anticipate Coors Light will continue to emphasize its cold, Rocky Mountain positioning as the World's Most Refreshing Beer. We expect it will also invest more than ever on digital and social channels to engage and recruit 21-34 year olds. Miller Lite , the original light beer with less carbs and calories, plans to further enhance its competitive messaging to drive greater consumer affinity and brand switching from its major competitor.
In Canada, our First Choice Commercial excellence approach and capability is building. In terms of commercial performance, there are multiple highlights. Our total share trend has improved three quarters in a row and Coors Light’s segment share also improved three quarters in a row, improving to flat in the fourth quarter. Craft volume grew driven by Belgian Moon and Creemore and our non-alcoholic portfolio of Coors Edge and Heineken 0.0 is delivering strong volume and segment share growth. In the value segment, we delivered strong share growth in 2018 driven by our simplified portfolio strategy and the launch of Miller High Life . As we look at 2019 and beyond, we believe there is growth potential from our innovation pipeline. Coors Slice , for example, is an innovation that strengthens the Coors trademark, and we are encouraged by the tests behind our pending introduction of Aqua-Relle , our hard sparkling water. Our commitment to customer excellence includes the adoption of BeerMate to strengthen field sales management and promising joint business plan pilots with key customers. For example, a pilot with Ontario’s LCBO is producing beer category growth well in excess of the total industry performance. Our two largest brands will benefit from new advertising, brand redesign, and innovation in 2019. For Coors Light , we launch our new “The Mountains Are Calling” campaign and introduce new packages, including a new chill pack in
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Our U.K. pension plan includes benefits linked to inflation. The above sensitivity analysis does not consider the implications to inflation resulting from the above contemplated discount rate changes. This sensitivity holds all other assumptions constant.
## Long-Term Expected Rates of Return on Assets
The assumed long-term expected return on assets is used to estimate the actual return that will occur on each individual funded plan's respective plan assets in the upcoming year. We determine each plan's EROA with substantial input from independent investment specialists, including our actuaries and other consultants. In developing each plan's EROA, we consider current and expected asset allocations, historical market rates as well as historical and expected returns on each plan's individual asset classes. In developing future return expectations for each of our plan's assets, we evaluate general market trends as well as key elements of asset class returns such as expected earnings growth, yields and spreads. The calculation includes inputs for interest, inflation, credit, and risk premium (active investment management) rates and fees paid to service providers. Based on the above factors and expected asset allocations, we have assumed, on a weighted-average basis, an EROA of 4.38% for our defined benefit pension plan assets for cost recognition in 2019. This is an increase from the weighted-average rate of 4.10% we had assumed in 2018. We believe that our EROA assumptions are appropriate; however, significant changes in our assumptions or actual returns that differ significantly from estimated returns may materially affect our net periodic pension costs.
To compute the expected return on plan assets, we apply the EROA to the market-related value of the pension plan assets adjusted for projected benefit payments to be made from the plan assets and projected contributions to the plan assets. We use the fair value approach to calculate the market-related value of pension plan assets used to determine net periodic pension cost, which includes measuring the market-related value of plan assets at fair value for purposes of determining the expected return on plan assets and amount of gain or loss subject to amortization.
A 50 basis point change in our discount rate and expected return on assets assumptions made at the beginning of 2018 would have had the following effects on 2018 net periodic pension and postretirement benefit costs:
<img src='content_image/1029612.jpg'>
## Fair Value of Plan Assets
We recognize our defined benefit pension plans as assets or liabilities in the consolidated balance sheets based on their underfunded or overfunded status as of our year end and recognize changes in the funded status due to changes in actuarial assumptions in the year in which the changes occur within other comprehensive income. Our funded status of our defined benefit pension plans is measured as the difference between each plan's projected benefit obligation and its assets' fair values. The fair value of plan assets is determined by us using available market information and appropriate valuation methodologies. However, considerable judgment is required in selecting an appropriate methodology and interpreting market data to develop the estimates of fair value, especially in the absence of quoted market values in an active market. Changes in these assumptions or the use of different market inputs may have a material impact on the estimated fair values or the ultimate amount at which the plan assets are available to satisfy our plan obligations.
Equity assets are diversified between domestic and other international investments. Relative allocations reflect the demographics of the respective plan participants. See Part II—Item 8 Financial Statements and Supplementary Data, Note 15, "Employee Retirement Plans and Postretirement Benefits" of the Notes for a comparison of target asset allocation percentages to actual asset allocations as of December 31, 2018.
## Other Considerations
Our net periodic pension and postretirement benefit costs are also influenced by the potential amortization (or non-amortization) from accumulated other comprehensive income (loss) of deferred gains and losses, which occur when actual experience differs from estimates. We employ the corridor approach for determining each plan's amortization. This approach defines the “corridor” as the greater of 10% of the PBO or 10% of the market-related value of plan assets (as discussed above)
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While historical performance and current expectations have resulted in fair values of our reporting units in excess of carrying values, if our assumptions are not realized, it is possible that an impairment charge may need to be recorded in the future. For example, a 50 basis point increase in our discount rate assumptions, which is within a reasonable range of historical discount rate fluctuations between test dates, would have had the following effects on the fair value cushion in excess of carrying value for the U.S., Europe and Canada reporting units as of the October 1, 2018, test date:
<img src='content_image/1052966.jpg'>
Post sensitivity, the fair values of the U.S., Europe and Canada reporting units remain in excess of the their carrying values. The discount rate sensitivity holds all other assumptions and inputs constant.
Regarding definite-lived intangibles, we continuously monitor the performance of the underlying asset for potential triggering events suggesting an impairment review should be performed. Excluding the definite-lived intangible asset impairment charge associated with the triggering event that occurred in Bihar, India, which resulted in an impairment of tangible assets of $11.0 million and impairment of goodwill and definite-lived intangibles of $19.8 million in 2016, no such triggering events resulting in an impairment charge were identified in 2018, 2017 or 2016. See Part II—Item 8 Financial Statements and Supplementary Data, Note 10, "Goodwill and Intangible Assets" of the Notes for further discussion.
As of December 31, 2018, the carrying values of goodwill and intangible assets were approximately $8.3 billion and $13.8 billion, respectively. If actual performance results differ significantly from our projections or we experience significant fluctuations in our other assumptions, a material impairment charge may occur in the future. See Part II—Item 8 Financial Statements and Supplementary Data, Note 10, "Goodwill and Intangible Assets" of the Notes for further discussion and presentation of these amounts.
## Income Taxes
Income taxes are accounted for in accordance with U.S. GAAP. Judgment is required in determining our consolidated provision for income taxes. In the ordinary course of our global business, there are many transactions for which the ultimate tax outcome is uncertain. Additionally, our income tax provision is based on calculations and assumptions that are subject to examination by many different tax authorities. See Part II—Item 8 Financial Statements and Supplementary Data, Note 6, "Income Tax" of the Notes for further discussion on the implications of the 2017 Tax Act in the U.S. on our financial statements.
We are periodically subject to tax return audits by both foreign and domestic tax authorities, which can involve questions regarding our tax positions. Settlement of any challenge resulting from these audits can result in no change, a complete disallowance, or some partial adjustment reached through negotiations or litigation. We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained based on its technical merits. We measure and record the tax benefits from such a position based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. Our estimated liabilities related to these matters are adjusted in the period in which the uncertain tax position is effectively settled, the statute of limitations for examination expires or when additional information becomes available. Our liability for unrecognized tax benefits requires the use of assumptions and significant judgment to estimate the exposures associated with our various filing positions. Although we believe that the judgments and estimates made are reasonable, actual results could differ and resulting adjustments could materially affect our effective income tax rate and income tax provision.
We provide for taxes that may be payable if undistributed earnings of overseas subsidiaries were to be remitted to the U.S., except for those earnings that we consider to be permanently reinvested. However, we continue to monitor the impacts of the 2017 Tax Act, as defined in Part II— Item 8 Financial Statements and Supplementary Data, Note 6, "Income Tax," including yet to be issued regulations and interpretations, on the tax consequences of future repatriations. Future sales of foreign subsidiaries are not exempt from capital gains tax in the U.S. under the 2017 Tax Act. We have no plans to dispose of any of our foreign subsidiaries and are not recording deferred taxes on outside basis differences in foreign subsidiaries for the sale of a foreign subsidiary.
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We record a valuation allowance to reduce our deferred tax assets to the amount that is more likely than not to be realized. We evaluate our ability to realize the tax benefits associated with deferred tax assets by assessing the adequacy of future expected taxable income, including the reversal of existing temporary differences, historical and projected operating results, and the availability of prudent and feasible tax planning strategies. The realization of tax benefits is evaluated by jurisdiction and the realizability of these assets can vary based on the character of the tax attribute and the carryforward periods specific to each jurisdiction. In the event we were to determine that we would be able to realize our deferred tax assets in the future in excess of its net recorded amount, an adjustment to the deferred tax asset would decrease income tax expense in the period a determination was made. Likewise, should we determine that we would not be able to realize all or part of our net deferred tax asset in the future, an adjustment to the deferred tax asset would be recorded to income tax expense in the period such determination was made.
## New Accounting Pronouncements
## New Accounting Pronouncements Not Yet Adopted
## Leases
In February 2016, the FASB issued authoritative guidance intended to increase transparency and comparability among organizations by requiring the recognition of lease assets and liabilities on the balance sheet and disclosure of key information about leasing arrangements. We will adopt this guidance and all related amendments applying the modified retrospective transition approach to all lease arrangements as of the effective date of adoption, January 1, 2019. Additionally, for existing leases as of the effective date, we will elect the package of practical expedients available at transition to not reassess the historical lease determination, lease classification and initial direct costs.
For operating leases, the adoption of this new guidance is currently expected to result in the recognition of right-of-use ("ROU") assets of between approximately $150 million and $160 million, and aggregate current and non-current lease liabilities of between approximately $160 million and $170 million, as of the effective date of adoption, including immaterial reclassifications of prepaid and deferred rent balances into ROU assets. Additionally, as a result of the cumulative impact of adopting the new guidance, we expect to record a net increase to opening retained earnings of between $30 million and $35 million as of January 1, 2019, with the offsetting impact within other assets, related to our share of the accelerated recognition of deferred gains on non-qualifying and other sale-leaseback transactions by an equity method investment within our Canada segment. We are in the process of finalizing this transition adjustment calculation, which will be completed during the first quarter of 2019. Additionally, while our accounting for finance leases will remain unchanged at adoption, we will prospectively change the presentation of finance lease liabilities within the consolidated balance sheets to be presented within current portion of long-term debt and short-term borrowings and long-term debt, as appropriate. The adoption of this guidance is not expected to impact our cash flows from operating, investing, or financing activities.
Other than the items noted above, there have been no new accounting pronouncements not yet effective that we believe have a significant impact, or potential significant impact, to our consolidated financial statements.
See Part II-Item 8 Financial Statements and Supplementary Data, Note 2, "New Accounting Pronouncements" of the Notes for a description of new accounting pronouncements.
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## Brands sold in the U.S.
## Global priority brands
Blue Moon Coors Banquet Coors Light Miller Genuine Draft Miller Lite
## Hard cider brands
Crispin Smith & Forge
(1) Under perpetual royalty-free license from Asahi.
(2) Under license from Heineken.
(3) In partnership with Hornell Brewing, an affiliate of Arizona Beverages
(4) Under perpetual royalty-free license from ABI.
## Brands sold in Canada
## Global priority brands
Belgian Moon Coors Banquet Coors Light Miller Genuine Draft Miller Lite
## Licensed premium import brands (1)
Amstel Light Heineken Murphy's Newcastle Strongbow cider
(1) Under license from Heineken.
## Regional champion brands
Hamm's Icehouse Keystone Mickey's Miller64 Miller High Life Milwaukee's Best Olde English Steel Reserve
## Flavored malt beverages
Arnold Palmer Spiked (3) Henry's Hard Redd's (4) Steel Reserve Alloy Series
## National champion and other regional brands
Carling Carling Black Label Keystone Mad Jack Miller High Life Molson Canadian Molson Canadian 67 Molson Canadian Cider Molson Dry Molson Export Old Style Pilsner Rickard's
Desperados Dos Equis Moretti Sol Tecate
## Craft and import brands
Grolsch (1) Hop Valley Leinenkugel's Peroni Nastro Azurro (1) Pilsner Urquell (1) Revolver Saint Archer Sol (2) Terrapin
## Craft and import brands
Brasseurs de Montréal Creemore Springs Granville Island Henry's Hard Le Trou du Diable Leinenkugel's
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## MOLSON COORS BREWING COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (IN MILLIONS)
<img src='content_image/1037140.jpg'>
See notes to consolidated financial statements.
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## MOLSON COORS BREWING COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND NONCONTROLLING INTERESTS (Continued)
## (IN MILLIONS)
<img src='content_image/1039963.jpg'>
See notes to consolidated financial statements.
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## Our Segments
In 2018, we operated the following segments: the U.S., Canada, Europe and International. A separate operating team manages each segment and each segment manufactures, markets, and sells beer and other malt beverage products.
## United States Segment
• Headquarters: Chicago, Illinois
• Approximately 7,300 employees
• Second largest brewer by volume in the U.S., selling approximately 24% of the total 2018 U.S. brewing industry shipments (excluding exports)
• Currently operating seven primary breweries, six craft breweries and two container operations
Prior to the Acquisition completed on October 11, 2016, MCBC owned a 50% voting and 42% economic interest in MillerCoors (which was originally formed on July 1, 2008, as a joint venture between MCBC and SABMiller), and MillerCoors was accounted for under the equity method of accounting. Following the completion of the Acquisition, MillerCoors became a wholly-owned subsidiary of MCBC and its results were fully consolidated by MCBC prospectively beginning on October 11, 2016.
## Sales and Distribution
In the United States, beer is generally distributed through a three-tier system consisting of manufacturers, distributors and retailers. A national network of approximately 400 independent distributors and one owned distributor, Coors Distributing Company, purchases our products and distributes them to on- and off-premise retail accounts.
References to on- and off-premise sales volumes are the sales to retailers of these distributors, which we believe is a useful data point relative to consumer trends.
## Channels
In the United States, the on-premise channel industry volume, which includes sales in bars and restaurants, declined approximately 2% in 2018.
The off-premise channel includes sales in convenience stores, grocery stores, liquor stores and other retail outlets. The off-premise channel industry volume declined approximately 1% in 2018 versus prior year.
The following table reflects the industry channel trends over the last five years in the United States. Note that percentages reflect estimates based on market data currently available.
<img src='content_image/1052834.jpg'>
Coors Distributing Company distributed less than 2% of our total owned and non-owned volume in 2018.
Manufacturing, Production and Packaging
## Brewing Raw Materials
We use high quality ingredients to brew our products. We malt a portion of our production requirements, using barley purchased under primarily annual contracts from independent farmers located predominantly in the western United States. Other barley, malt, and cereal grains are purchased from suppliers primarily in the U.S. Hops are purchased from suppliers in the U.S. and Europe. We both own and lease water rights, as well as purchase water through local municipalities, to provide for and sustain brewing operations in case of a prolonged drought in the regions where we have operations. We do not currently anticipate future difficulties in accessing water or agricultural products used in our brewing process in the near term.
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<img src='content_image/1032742.jpg'>
The impacts of the restatement have been reflected throughout the financial statements, including the applicable footnotes, as appropriate.
## Revenue Recognition
We account for revenue in accordance with Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers, which we adopted on January 1, 2018, using the modified retrospective transition approach (see Note 2, "New Accounting Pronouncements" for impacts of adoption).
Our net sales represent the sale of beer and other malt beverages (including adjacencies, such as cider and hard soda), net of excise tax. Sales are stated net of incentives, discounts and returns. Sales of products are for cash or otherwise agreed upon credit terms. Our payment terms vary by location and customer, however, the time period between when revenue is recognized and when payment is due is not significant. Our revenue generating activities have a single performance obligation and are recognized at the point in time when control transfers and our obligation has been fulfilled, which is when the related goods are shipped or delivered to the customer, depending upon the method of distribution and shipping terms. Where our products are sold under consignment arrangements, revenue is not recognized until control has transferred, which is when the product is sold to the end customer. Revenue is measured as the amount of consideration we expect to receive in exchange for the sale of our product. The cost of various programs, such as price promotions, rebates and coupons are treated as a reduction of sales. In certain of our markets, we make cash payments to customers such as slotting or listing fees, or payments for other marketing or promotional activities. These cash payments are recorded as a reduction of revenue unless we receive a distinct good or service as defined under ASC 606. Specifically, a good or service is considered distinct when it is separately identifiable from other promises in the contract, we receive a benefit from the good or service, and the benefit is separable from the sale of our product to the customer.
Certain payments made to customers are conditional on the achievement of volume targets, marketing commitments, or both. If paid in advance, we record such payments as prepayments and amortize them over the relevant period to which the customer commitment is made (generally up to five years). When the payment is not for a distinct good or service, or fair value cannot be reasonably estimated, the amortization of the prepayment or the cost as incurred is recorded as a reduction of revenue. Where a distinct good or service is received and fair value can be reasonably estimated, the cost is included as marketing, general and administrative expenses. The amounts deferred are reassessed regularly for recoverability over the contract period and are impaired where there is objective evidence that the benefits will not be realized or the asset is otherwise not recoverable. Separately, as discussed below, we analyze whether these advance payments contain a significant financing component for potential adjustment to the transaction price.
Our primary revenue generating activity represents the sale of beer and other malt beverages to customers, including both domestic and exported product sales. Our customer could be a distributor, retail or on-premise outlet, depending on the market. The majority of our revenues are generated from brands that we own and brew ourselves, however, we also import or brew and sell certain non-owned partner brands under licensing and related arrangements. In addition, primarily in the U.K., as well as certain other countries in our Europe segment, we sell other beverage companies' products to on-premise customers to provide them with a full range of products for their retail outlets. We refer to this as the "factored brand business." Sales from this business are included in our net sales and cost of goods sold when ultimately sold. In the factored brand business, we normally purchase inventory, which includes excise taxes charged by the vendor, take orders from customers for such brands, negotiate with the customers on pricing and invoice customers for the product and related costs of delivery. In addition, we incur the risk of loss at times we are in possession of the inventory and for the receivables due from the customers. Revenues for owned brands, partner and imported brands, as well as factored brands are recognized at the point in time when control is transferred to the customer as discussed above.
## Other Revenue Generating Activities
We contract manufacture for other brewers in some of our markets. These contractual agreements require us to brew, package and ship certain brands to these brewers, who then sell the products to their own customers in their respective markets.
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Revenues under contract brewing arrangements are recognized when our obligation related to the finished product is fulfilled and control of the product transfers to these other brewers.
We also have licensing agreements with third party partners who brew and distribute our products in various markets across our segments. Under these agreements, we are compensated based on the amount of products sold by our partners in these markets at an agreed upon royalty rate or profit percentage. We apply the sales-based royalty practical expedient to these licensing arrangements and recognize revenue as product is sold by our partners at the agreed upon rate.
We have evaluated these other revenue generating activities under the disaggregation disclosure criteria outlined within the guidance and concluded that these other revenue generating activities are immaterial for separate disclosure. See Note 3, "Segment Reporting," for disclosure of revenues by geographic segment.
## Variable Consideration
Our revenue generating activities include variable consideration which is recorded as a reduction of the transaction price based upon expected amounts at the time revenue for the corresponding product sale is recognized. For example, customer promotional discount programs are entered into with certain distributors for certain periods of time. The amount ultimately reimbursed to distributors is determined based upon agreed-upon promotional discounts which are applied to distributors' sales to retailers. Other common forms of variable consideration include volume rebates for meeting established sales targets, and coupons and mail-in rebates offered to the end consumer. The determination of the reduction of the transaction price for variable consideration requires that we make certain estimates and assumptions that affect the timing and amounts of revenue and liabilities recorded. We estimate this variable consideration, including analyzing for a potential constraint on variable consideration, by taking into account factors such as the nature of the promotional activity, historical information and current trends, availability of actual results, and expectations of customer and consumer behavior.
We do not have standard terms that permit return of product; however, in certain markets where returns occur we estimate the amount of returns as variable consideration based on historical return experience and adjust our revenue accordingly. Products that do not meet our high quality standards are returned by the customer or recalled and destroyed and are recorded as a reduction of revenue. The reversal of revenue is recorded upon determination that the product will be recalled and destroyed. We estimate the costs required to facilitate product returns and record them in cost of goods sold as required.
During the twelve months ended December 31, 2018, adjustments to revenue from performance obligations satisfied in the prior period due to changes in estimates in variable consideration were immaterial.
## Significant Financing Component and Costs to Obtain Contracts
In certain of our businesses where such practices are legally permitted, we make loans or advanced payments to retail outlets that sell our brands. For arrangements that do not span greater than one year, we apply the practical expedient available under ASC 606 and do not adjust the transaction price for the effects of a potential significant financing component. We further analyze arrangements that span greater than one year on an ongoing basis to determine whether a significant financing component exists. No such arrangements existed during the twelve months ended December 31, 2018.
Advance payments to customers, where legally permitted, are deferred and amortized as a reduction to revenue over the expected period of benefit and tested for recoverability as appropriate. All other costs to obtain contracts and fulfill are expensed as incurred based on the nature, significance and expected benefit of these costs relative to the contract.
## Contract Assets and Liabilities
We continually evaluate whether our revenue generating activities and advanced payment arrangements with customers result in the recognition of contract assets or liabilities. No such assets or liabilities existed as of December 31, 2018, or December 31, 2017. Separately, trade accounts receivable, including affiliate receivables, approximates receivables from contracts with customers.
## Shipping and Handling
Freight costs billed to customers for shipping and handling are recorded as revenue. Shipping and handling expense related to costs incurred to deliver product are recognized within cost of goods sold. We account for shipping and handling activities that occur after control has transferred as a fulfillment cost as opposed to a separate performance obligation, and the costs of shipping and handling are recognized concurrently with the related revenue.
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amortization. Amortization is recorded using the straight-line method over the estimated lives of the assets as this approximates the pattern in which the assets economic benefits are consumed.
## Equity Method Investments
We apply the equity method of accounting to 20% to 50% owned investments where we exercise significant influence or VIEs for which we are not the primary beneficiary. We use the cumulative earnings approach for determining cash flow presentation of cash distributions received from equity method investees. Distributions received are included in our consolidated statements of cash flows as operating activities, unless the cumulative distributions exceed our portion of the cumulative equity in the net earnings of the equity method investment, in which case the excess distributions are deemed to be returns of the investment and are classified as investing activities in our consolidated statements of cash flows. Equity method investments as of December 31, 2018, include Brewers' Retail, Inc. ("BRI") and Brewers' Distributor Ltd. ("BDL") in Canada.
There are no related parties that own interests in our equity method investments as of December 31, 2018.
## Derivative Hedging Instruments
We use derivatives as part of our normal business operations to manage our exposure to fluctuations in interest rates, foreign currency exchange, commodity prices, production and packaging material costs and for other strategic purposes related to our core business. We enter into derivatives for risk management purposes only, including derivatives designated in hedge accounting relationships as well as those derivatives utilized as economic hedges. We do not enter into derivatives for trading or speculative purposes. We recognize our derivatives on the consolidated balance sheets as assets or liabilities at fair value and are classified in either current or non-current assets or liabilities based on each contract's respective unrealized gain or loss position and each contract's respective maturity. Our policy is to present all derivative balances on a gross basis, without regard to counterparty master netting agreements or similar arrangements. Further, our current derivative agreements do not allow us to net positions with the same counterparty and therefore, we present our derivative positions gross in our consolidated balance sheets.
Changes in fair values of outstanding cash flow and net investment hedges are recorded in OCI, until earnings are affected by the variability of cash flows of the underlying hedged item or the sale of the underlying net investment, respectively. Effective cash flow hedges offset the gains or losses recognized on the underlying exposure in the consolidated statements of operations, or for net investment hedges, the foreign exchange translation gain or loss recognized in AOCI. Changes in fair value of outstanding fair value hedges and the offsetting changes in fair value of the hedged item are recognized in earnings. Changes in fair value of the derivative attributable to components allowed to be excluded from the assessment of hedge effectiveness are deferred in AOCI and recognized in earnings over the life of the hedge.
We record realized gains and losses from derivative instruments in the same financial statement line item as the hedged item/forecasted transaction. Changes in unrealized gains and losses for derivatives not designated in a hedge accounting relationship are recorded directly in earnings each period and are also recorded in the same financial statement line item as the hedged item/forecasted transaction. Cash flows from the settlement of derivatives, including both economic hedges and those designated in hedge accounting relationships, appear in the consolidated statements of cash flows in the same categories as the cash flows of the hedged item.
In accordance with authoritative accounting guidance, we do not record the fair value of derivatives for which we have elected the Normal Purchase Normal Sale ("NPNS") exemption. We account for these contracts on an accrual basis, recording realized settlements related to these contracts in the same financial statement line items as the corresponding transaction.
## Pension and Postretirement Benefits
We maintain retirement plans for the majority of our employees. We offer different types of plans within each segment, including defined benefit plans, defined contribution plans and OPEB plans. Each plan is managed locally and in accordance with respective local laws and regulations. Our equity investments, BRI and BDL, maintain defined benefit, defined contribution and postretirement benefit plans as well.
We recognize the underfunded or overfunded status of a defined benefit postretirement plan as an asset or liability in the consolidated balance sheets and recognize changes in the funded status in the year in which the changes occur within OCI. The funded status of a plan, measured as the difference between the fair value of plan assets and the projected benefit obligation, and the related net periodic pension cost are calculated using a number of significant actuarial assumptions. Changes in net periodic pension cost and funding status may occur in the future due to changes in these assumptions.
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In 2019, the Company determined that the $26 million carrying value of certain non-core assets exceeded their respective fair value less costs to sell and recognized a $16 million non-cash impairment. The Company used Level 3 measurements to determine the fair value of these assets.
In the third quarter of 2018, the Company determined the carrying value of certain non-full cost pool assets associated with the Fayetteville Shale sale exceeded the fair value less costs to sell. In accordance with accounting guidance for Property, Plant and Equipment, assets held for sale are measured at the lower of carrying value or fair value less costs to sell. Because the assets outside of the full cost pool included in the Fayetteville Shale sale met the criteria for held for sale accounting, the Company recorded a non-cash impairment charge of $161 million for the year ended December 31, 2018, of which $145 million related to midstream gathering assets and $15 million related to E&P which were both reflected as assets held for sale in the third quarter of 2018. Additionally, the Company recorded a $1 million non-cash impairment related to other non-core assets that were not included in the sale. The estimated fair value of the gathering assets was based on an estimated discounted cash flow model and market assumptions. The significant Level 3 assumptions used in the calculation of estimated discounted cash flows included future commodity prices, projections of estimated quantities of natural gas reserves, operating costs, projections of future rates of production, inflation factors and risk adjusted discount rates.
## (9) DEBT
The components of debt as of December 31, 2020 and 2019 consisted of the following:
<img src='content_image/1053722.jpg'>
<img src='content_image/1053723.jpg'>
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## St. Lucie County Fire District Firefighters’ Pension Trust
On October 17, 2016, the St. Lucie County Fire District Firefighters’ Pension Trust filed a putative class action in the 61st District Court in Harris County, Texas, against the Company, certain of its former officers and current and former directors and the underwriters on behalf of itself and others that purchased certain depositary shares from the Company’s January 2015 equity offering, alleging material misstatements and omissions in the registration statement for that offering. The Company removed the case to federal court, but after a decision by the United States Supreme Court in an unrelated case that these types of cases are not subject to removal, the federal court remanded the case to the Texas state court. The Texas trial court denied the Company’s motion to dismiss, and in February 2020, the court of appeals declined to exercise discretion to reverse the trial court’s decision. The Company filed a petition to review the trial court’s decision with the Texas Supreme Court, and the Court requested a response from the plaintiff. The Court subsequently ordered full briefing on the merits of the case. The Company carries insurance for the claims asserted against it and the officer and director defendants, and the carrier has accepted coverage. The Company denies all allegations and intends to continue to defend this case vigorously. The Company does not expect this case to have a material adverse effect on the results of operations, financial position or cash flows of the Company. Additionally, it is not possible at this time to estimate the amount of any additional loss, or range of loss, that is reasonably possible.
## Indemnifications
The Company has provided certain indemnifications to various third parties, including in relation to asset and entity dispositions, securities offerings and other financings, such as the St. Lucie County Fire District Firefighters’ Pension Trust case described above. In the case of asset dispositions, these indemnifications typically relate to disputes, litigation or tax matters existing at the date of disposition. The Company likewise obtains indemnification for future matters when it sells assets, although there is no assurance the buyer will be capable of performing those obligations. In the case of equity offerings, these indemnifications typically relate to claims asserted against underwriters in connection with an offering. No material liabilities have been recognized in connection with these indemnifications.
## (11) INCOME TAXES
The provision (benefit) for income taxes included the following components:
<img src='content_image/1039610.jpg'>
The provision for income taxes was an effective rate of (15)% in 2020, (86)% in 2019 and 0% in 2018. The Company’s effective tax rate increased in 2020, as compared with 2019, primarily due to the increase in the valuation allowance in 2020. The following reconciles the provision for income taxes included in the consolidated statements of operations with the provision which would result from application of the statutory federal tax rate to pre-tax financial income:
<img src='content_image/1039611.jpg'>
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[
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] |
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The 2020 tax accrual calculated under the estimated annual effective tax rate method reflects the Tax Reform Act changes that took effect January 1, 2018. The components of the Company’s deferred tax balances as of December 31, 2020 and 2019 were as follows:
<img src='content_image/1042220.jpg'>
The Tax Reform Act made significant changes to the U.S. federal income tax law affecting the Company. Major changes in this legislation applicable to the Company relate to the reduction in the corporate tax rate to 21%, repeal of the alternative minimum tax, interest deductibility and net operating loss carryforward limitations, changes to certain executive compensation and full expensing provisions related to business assets. The adjustments required to deferred taxes as a result of the Tax Reform Act have been reflected in the Company’s tax provision.
As the Tax Reform Act repealed the corporate alternative minimum tax for tax years beginning on or after January 1, 2018 and provided for existing alternative minimum tax credit carryovers to be refunded beginning in 2018, the Company has approximately $30 million in refundable credits. Accordingly, in 2017 the valuation allowance in place prior to the Tax Reform Act related to these credits was released, and any credits remaining were reclassed to a receivable. Additionally, in January 2020 the IRS announced that any previously sequestered amounts relating to these alternative minimum tax refunds would also be refunded. The Company had approximately $2 million in sequestered amounts relating to alternative minimum tax refunds. All of those refunds have been received as of December 2020 after the CARES Act (enacted in March 2020) accelerated alternative minimum tax refunds.
In 2020, the Company received refunds related to federal income tax of $32 million. The Company received a refund of $1 million in state income tax in 2019 and paid $6.3 million in state income tax in 2018. The Company’s net operating loss carryforward as of December 31, 2020 was $4.5 billion and $2 billion for federal and state reporting purposes, respectively, the majority of which will expire between 2035 and 2039. Included in the Company's net operating loss carryforward are the net operating loss carryforwards acquired in the Montage acquisition of $1 billion. A portion of the Montage-related net operating loss carryovers are subject to an annual section 382 limitation of $1.7 million, and the Company has appropriately accounted for this limitation in purchase accounting. In addition, certain net operating loss carryovers are subject to a section 382 limitation of $90 million, but the Company does not expect this limit to have a material impact on its net operating loss carryforward balance. Additionally, the Company has an income tax net operating loss carryforward related to its Canadian operations of $29 million, with expiration dates of 2030 through 2039. The Company also had a statutory depletion carryforward of $13 million and $55 million related to interest deduction carryforward as of December 31, 2020.
A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income, and considers the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as current and forecasted business economics of the oil and gas industry.
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## (12) ASSET RETIREMENT OBLIGATIONS
The following table summarizes the Company’s 2020 and 2019 activity related to asset retirement obligations:
<img src='content_image/1044542.jpg'>
## (13) RETIREMENT AND EMPLOYEE BENEFIT PLANS
## 401(k) Defined Contribution Plan
The Company has a 401(k) defined contribution plan covering eligible employees. The Company expensed $2 million, $2 million and $3 million of contribution expense in 2020, 2019 and 2018, respectively. Additionally, the Company capitalized $1 million of contributions in 2020 and $1 million and $2 million in 2019 and 2018, respectively, directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties or directly related to the construction of the Company’s gathering systems.
## Defined Benefit Pension and Other Postretirement Plans
Prior to January 1, 1998, the Company maintained a traditional defined benefit plan with benefits payable based upon average final compensation and years of service. Effective January 1, 1998, the Company amended its pension plan to become a “cash balance” plan on a prospective basis for its non-bargaining employees. A cash balance plan provides benefits based upon a fixed percentage of an employee’s annual compensation. As part of ongoing effort to reduce costs, the Company has elected to freeze its pension plan effective January 1, 2021. Employees that were participants in the pension plan prior to January 1, 2021 will continue to receive the interest component of the plan but will no longer receive the service component. The Company’s funding policy is to contribute amounts which are actuarially determined to provide the plans with sufficient assets to meet future benefit payment requirements and which are tax deductible.
The postretirement benefit plan provides contributory health care and life insurance benefits. Employees become eligible for these benefits if they meet age and service requirements. Generally, the benefits paid are a stated percentage of medical expenses reduced by deductibles and other coverages.
Prior to January 1, 2021, substantially all of the Company’s employees were covered by the defined benefit pension. Substantially all of the Company’s employees continue to be covered by the postretirement benefit plans. The Company accounts for its defined benefit pension and other postretirement plans by recognizing the funded status of each defined pension benefit plan and other postretirement benefit plan on the Company’s balance sheet. In the event a plan is overfunded, the Company recognizes an asset. Conversely, if a plan is underfunded, the Company recognizes a liability.
In June 2018, the Company notified affected employees of a workforce reduction plan, which resulted primarily from a previously announced study of structural, process and organizational changes to enhance shareholder value. In December 2018, the Company closed the sale of the equity in certain of its subsidiaries that owned and operated its Fayetteville Shale E&P and related midstream gathering assets in Arkansas. As part of this transaction, many employees associated with those assets were either transferred to the buyer or their employment was terminated. As a result of the restructurings, the Company recognized a curtailment on its pension and other postretirement benefit plans and recognized a non-cash gain of $4 million on its consolidated statements of operations for the year ended December 31, 2018. In 2019, the Company recognized a $6 million non-cash settlement loss related to $21 million of lump sum payments as a result of these restructuring events. In 2020, the settlement loss was immaterial.
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"content_image/1057771.jpg",
"content_image/1057772.jpg"
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## Table of Contents
## Index to Financial Statements
2019 and 2018, respectively. As of December 31, 2020, there was $1 million of total unrecognized compensation cost related to unvested shares of restricted stock that is expected to be recognized over a weighted-average period of less than one year.
The following table summarizes the restricted stock activity for the years 2020, 2019 and 2018, and provides information for restricted stock outstanding at December 31 of each year:
<img src='content_image/1057770.jpg'>
(1) Includes 171,813 shares forfeited as a result of the reduction in workforce for the year end December 31, 2020.
(2) Includes 65,196 shares forfeited as a result of the reduction in workforce for the year ended December 31, 2019.
(3) Includes 1,287,636 shares forfeited as a result of the reduction in workforce for the year ended December 31, 2018.
The fair values of the grants were $2 million for 2020, $2 million for 2019 and $2 million for 2018. The total fair value of shares vested were $6 million for 2020, $11 million for 2019 and $19 million for 2018.
## Equity-Classified Restricted Stock Units
As a result of the Merger with Montage, certain Montage employees became employees of Southwestern and retained their original equity awards. The amount of compensation costs related these equity-classified restricted stock units recorded by the Company was immaterial for the year ended December 31, 2020. As of December 31, 2020, there was less than $1 million of total unrecognized compensation cost related to unvested equity-classified restricted stock units that is expected to be recognized over a weighted-average period of approximately one year.
The following table summarizes equity-classified restricted stock unit activity to be paid out in Company stock for the year ended December 31, 2020.
<img src='content_image/1057771.jpg'>
## Equity-Classified Performance Units
The Company recorded compensation costs related to equity-classified performance units for the years ended December 31, 2020, 2019 and 2018. The performance units awarded in 2017 included a market condition based on relative Total Shareholder Return (“TSR”). The grant date fair value is calculated using the closing price of the Company’s common stock at the grant date and a Monte Carlo model to estimate the TSR market condition. The estimated fair value is amortized to compensation expense on a straight-line basis over the vesting period of the award. There were no equity-classified performance units awarded in 2020, 2019 or 2018.
<img src='content_image/1057772.jpg'>
The Company also recorded a deferred tax asset of less than $1 million related to equity-classified performance units for the year ended December 31, 2020, compared to deferred tax assets of less than $1 million and $1 million in 2019 and 2018, respectively. As of December 31, 2020, there are no more equity-classified performance units outstanding.
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Company has accounted for these as liability-classified awards, and accordingly changes in the fair market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the awards. The performance unit awards granted in 2018 include a performance condition based on cash flow per debt-adjusted share and two market conditions, one based on absolute TSR and the other on relative TSR as compared to a group of the Company’s peers. The performance unit awards granted in 2019 include a performance condition based on return on average capital employed and two market conditions, one based on absolute TSR and the other on relative TSR. The performance unit awards granted in 2020 include a performance condition based on return on average capital employed and a market condition based on relative TSR. The fair values of all market conditions discussed above are calculated by Monte Carlo models on a quarterly basis.
<img src='content_image/1038482.jpg'>
The Company also recorded deferred tax assets of $2 million related to liability-classified performance units for the year ended December 31, 2020, compared to a reduction of deferred tax asset of less than $1 million and a deferred tax asset of $1 million for the years ended 2019 and 2018, respectively. As of December 31, 2020, there was $14 million of total unrecognized compensation cost related to liability-classified performance units. This cost is expected to be recognized over a weighted-average period of two years. The amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market. The final value of the performance unit awards is contingent upon the Company’s actual performance against the Performance Measures.
The following table summarizes liability-classified performance unit activity to be paid out in cash or stock for the years ended December 31, 2020, 2019 and 2018 and provides information for unvested units as of December 31, 2020, 2019 and 2018:
<img src='content_image/1038485.jpg'>
(1) Includes 518,450 units related to the reduction in workforce for the year ended December 31, 2020.
(2) Includes 375,086 units related to the reduction in workforce for the year ended December 31, 2019.
(3) Includes 295,160 units related to the reduction in workforce for the year ended December 31, 2018.
## Cash-Based Compensation
Performance Cash Awards
In 2020, the Company granted performance cash awards that vest over a four-year period and are payable in cash on an annual basis. The value of each unit of the award equal one dollar. The Company recognizes the cost of these awards as general and administrative expense, operating expense and capitalized expense over the vesting period of the awards. The performance cash awards granted in 2020 include a performance condition determined annually by the Company. In 2020, the performance measure is a targeted discretionary cash flow amount. If the Company, in its sole discretion, determines that the threshold was not met, the amount for that vesting period will not vest and will be cancelled.
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"content_image/1024380.jpg",
"content_image/1024379.jpg"
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The following table presents the breakout of other assets, which represent corporate assets not allocated to segments and assets for non- reportable segments for the years ended December 31, 2020, 2019 and 2018:
<img src='content_image/1024381.jpg'>
Included in intersegment revenues of the Marketing segment are $1.2 billion, $1.6 billion and $2.3 billion for 2020, 2019 and 2018, respectively, for marketing of the Company’s E&P sales. Corporate assets include cash and cash equivalents, furniture and fixtures and other costs. Corporate general and administrative costs, depreciation expense and taxes other than income are allocated to the segments.
## SUPPLEMENTAL QUARTERLY RESULTS (UNAUDITED)
The following is a summary of the quarterly results of operations for the years ended December 31, 2020 and 2019:
<img src='content_image/1024380.jpg'>
## SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)
The Company’s operating natural gas and oil properties are located solely in the United States. The Company also has licenses to properties in Canada, the development of which is subject to an indefinite moratorium. See “Our Operations – Other – New Brunswick, Canada” in Item 1 of Part 1 of this Annual Report.
## Net Capitalized Costs
The following table shows the capitalized costs of natural gas and oil properties and the related accumulated depreciation, depletion and amortization as of December 31, 2020 and 2019:
<img src='content_image/1024379.jpg'>
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Our ability to bring our Southwest Appalachia production to market will depend on a number of factors including the construction of and/or the availability of capacity on gathering systems and pipelines that we do not own. We refer you to “Marketing” within Item 1 of Part I of this Annual Report for a discussion of our gathering and transportation arrangements for Southwest Appalachia production.
## Other
Excluding 2,518,519 acres in New Brunswick, Canada, which have been subject to a government-imposed drilling moratorium since 2015, we held 9,764 net undeveloped acres for the potential development of new resources as of December 31, 2020 in areas outside of Appalachia. This compares to 27,334 net undeveloped acres held at year-end 2019, excluding the New Brunswick acreage.
We limited our activities in areas beyond our assets in Appalachia during 2020 and 2019 as a result of the commodity price environment as we focused our capital allocation on these more economically competitive plays. There can be no assurance that any prospects outside of our development plays will result in viable projects or that we will not abandon our initial investments.
New Brunswick, Canada. We currently hold exclusive licenses to search and conduct an exploration program covering 2,518,519 net acres in New Brunswick. In 2015, the provincial government in New Brunswick imposed a moratorium on hydraulic fracturing until it is satisfied with a list of conditions. In response to this moratorium, we requested and were granted an extension of its licenses to March 2021. In May 2016, the provincial government announced that the moratorium would continue indefinitely. Given this development, we fully impaired our investment in New Brunswick in 2016. We are currently working with Canadian officials to extend our licenses, although we cannot assure that the licenses will be extended past March 2021. Unless and until the moratorium is lifted, we will not be able to develop these assets.
## Acquisitions and Divestitures
In November 2020, we completed a merger with Montage Resources Corporation (the “Merger”) pursuant to which Montage merged with and into Southwestern, with Southwestern continuing as the surviving company. At the effective time of the Merger we acquired all of the outstanding shares of common stock in Montage in exchange for 1.8656 shares of our common stock per share of Montage common stock. The Merger expanded our footprint in Appalachia by supplementing our Northeast Appalachia and Southwest Appalachia operations and by expanding our operations into Ohio. See Note 3 to the consolidated financial statements of this Annual Report for more information on the Merger.
During 2019, we sold non-core acreage for $38 million. There was no production or proved reserves associated with this acreage.
## Capital Investments
<img src='content_image/1035023.jpg'>
(1) Includes $9 million and $35 million for the years ended December 31, 2020 and 2019 related to our water infrastructure project.
• The decrease in 2020 E&P capital investing, as compared to the prior year, resulted from reduced average well costs as well as our commitment to invest within our cash flows from operations, which are heavily dependent on commodity prices, supplemented by the remaining proceeds from the Fayetteville Shale sale.
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## Exhibit Number
## EXHIBIT INDEX
## Description
2.1 Agreement and Plan of Merger, dated as of August 12, 2020, by and between Southwestern Energy Company and Montage Resources Corporation (Incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K/A filed on August 12, 2020)
3.1 Amended and Restated Certificate of Incorporation of Southwestern Energy Company. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed May 24, 2010)
3.2 Amended and Restated Bylaws of Southwestern Energy Company, as amended on April 28, 2020. (Incorporated by reference to Exhibit 3.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020)
4.1 Description of the Company's Securities Registered under Section 12 of the Securities Exchange Act of 1934 (Incorporated by reference to Exhibit 4.1 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2019)
4.2 Form of Common Stock Certificate. (Incorporated by reference to Exhibit 4.4 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
4.3 Policy on Confidential Voting of Southwestern Energy Company. (Incorporated by reference to the Appendix of the Registrant’s Definitive Proxy Statement (Commission File No. 1-08246) for the 2006 Annual Meeting of Stockholders)
4.4 Indenture by and among Southwestern Energy Company, SEECO, Inc., Southwestern Energy Production Company, Southwestern Energy Services Company and The Bank of New York Trust Company, N.A., as trustee, dated as of March 5, 2012. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed March 6, 2012)
4.5 First Supplemental Indenture, dated as of November 29, 2017 between Southwestern Energy Company and The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed December 1, 2017)
4.6 Second Supplemental Indenture, dated as of April 26, 2018 between Southwestern Energy Company, the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on April 26, 2018)
4.7 Third Supplemental Indenture, dated as of September 17, 2018 between Southwestern Energy Company and The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on September 18, 2018)
4.8* Fourth Supplemental Indenture, dated as of December 10, 2020 between Southwestern Energy Company and The Bank of New York Mellon Trust Company, N.A., as trustee
4.9 Form of 4.10% Notes due 2022. (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on March 5, 2012)
4.10 Indenture, dated as of January 23, 2015 between Southwestern Energy Company and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on January 23, 2015)
4.11 First Supplemental Indenture, dated as of January 23, 2015 between Southwestern Energy Company and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on January 23, 2015)
4.12 Second Supplemental Indenture, dated as of September 25, 2017 between Southwestern Energy Company and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.5 to the Registrant’s Current Report on Form 8-K filed on September 25, 2017)
4.13 Third Supplemental Indenture, dated as of November 29, 2017 between Southwestern Energy Company and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on December 1, 2017)
4.14 Fourth Supplemental Indenture, dated as of April 26, 2018 between Southwestern Energy Company, the guarantors named therein and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on April 26, 2018)
4.15* Fifth Supplemental Indenture, dated as of December 3, 2018 between Southwestern Energy Company, the guarantors named therein and U.S. Bank National Association, as trustee
4.16* Sixth Supplemental Indenture, dated as of December 10, 2020 between Southwestern Energy Company, the guarantors named therein and U.S. Bank National Association, as trustee
4.17 Form of 4.95% Notes due 2025. (Incorporated by reference to Exhibit 4.5 to the Registrant’s Current Report on Form 8-K filed on January 23, 2015)
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## Index to Financial Statements
4.18 Indenture, dated as of September 25, 2017 between Southwestern Energy Company and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on September 25, 2017)
4.19 First Supplemental Indenture, dated as of September 25, 2017 between Southwestern Energy Company and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on September 25, 2017)
4.20 Second Supplemental Indenture, dated as of April 26, 2018 between Southwestern Energy Company, the guarantors named therein and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed on April 26, 2018)
4.21* Third Supplemental Indenture, dated as of December 3, 2018 between Southwestern Energy Company, the guarantors named therein and U.S. Bank National Association, as trustee
4.22 Fourth Supplemental Indenture, dated as of August 27, 2020 between Southwestern Energy Company, the guarantors named therein and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K filed on August 27, 2020)
4.23* Fifth Supplemental Indenture, dated as of December 10, 2020 between Southwestern Energy Company, the guarantors named therein and U.S. Bank National Association, as trustee
4.24 Form of 7.50% Notes due 2026. (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed on September 25, 2017)
4.25 Form of 7.75% Notes due 2027. (Incorporated by reference to Exhibit 4.4 to the Registrant’s Current Report on Form 8-K filed on September 25, 2017)
4.26 Form of 8.375% Notes due 2028. (Incorporated by reference to Exhibit 4.3 to the Registrant's Current Report on Form 8-K filed on August 27, 2020)
10.1 Form of Second Amended and Restated Indemnity Agreement between Southwestern Energy Company and each Executive Officer and Director of the Registrant. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
10.2 Form of Executive Severance Agreement between Southwestern Energy Company and each of the Executive Officers of Southwestern Energy Company, effective February 17, 1999. (Incorporated by reference to Exhibit 10.12 of the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1998)
10.3 Form of Amendment to Executive Severance Agreement between Southwestern Energy Company and each of the Executive Officers of Southwestern Energy Company prior to 2011. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Annual Report on Form 10- K (Commission File No. 1-08246) for the year ended December 31, 2008)
10.4 Form of Executive Severance Agreement between Southwestern Energy Company and Executive Officers Post 2011. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K (Commission File No.1-08426) for the year ended December 31, 2011)
10.5 Southwestern Energy Company Supplemental Retirement Plan as amended. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on February 19, 2008)
10.6 Southwestern Energy Company Non-Qualified Retirement Plan as amended. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on February 19, 2008)
10.7 Amendment One to the Southwestern Energy Company Non-Qualified Retirement Plan (Incorporated by reference to Exhibit 10.9 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2009)
10.8 Southwestern Energy Company 2013 Incentive Plan. (Incorporated by reference to Annex A of the Registrant’s Proxy Statement filed April 8, 2013)
10.9 First Amendment to Southwestern Energy Company 2013 Incentive Plan. (Incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K filed on May 20, 2016)
10.10 Second Amendment to Southwestern Energy Company 2013 Incentive Plan. (Incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K filed on May 30, 2017)
10.11 Third Amendment to Southwestern Energy Company 2013 Incentive Plan. (Incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K filed on May 22, 2019)
10.12 Southwestern Energy Company 2013 Incentive Plan Form of Performance Unit Award Agreement, for awards granted prior to February 25, 2020. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on March 8, 2018)
10.13 Southwestern Energy Company 2013 Incentive Plan Form of Performance Unit Award Agreement, for awards granted on or after February 25, 2020 and prior to February 23, 2021. (Incorporated by reference to Exhibit 10.13 to the Registrant's Annual Report on Form 10-K (Commission No. 001-08246) for the year ended December 31, 2019)
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10.36 Amendment No. 3 to Credit Agreement, dated as of April 26, 2018 among Southwestern Energy Company, JPMorgan Chase Bank N.A., as Administrative Agent, and each lender from time to time party thereto (Incorporated by reference to Exhibit 10.42 to the Registrant's Annual Report on Form 10-K (Commission No. 001-08246) for the year ended December 31, 2019)
10.37 Amendment No. 4 to Credit Agreement, dated as of April 26, 2018 among Southwestern Energy Company, JPMorgan Chase Bank N.A., as Administrative Agent, and each lender from time to time party thereto (Incorporated by reference to Exhibit 10.43 to the Registrant's Annual Report on Form 10-K (Commission No. 001-08246) for the year ended December 31, 2019)
10.38* Amendment No. 5 to Credit Agreement, dated as of April 26, 2018 among Southwestern Energy Company, JPMorgan Chase Bank N.A., as Administrative Agent, and each lender from time to time party thereto
10.39 Amendment No. 6 to Credit Agreement, dated as of July 31, 2020, among Southwestern Energy Company, the lenders party thereto and JP Morgan Chase Bank, N.A., as administrative agent for the lenders (Incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on on Form 10-Q filed on October 29, 2020)
10.40 Amendment No. 7 to Credit Agreement, dated as of August 18, 2020, among Southwestern Energy Company, the lenders party thereto and JP Morgan Chase Bank, N.A., as administrative agent for the lenders (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed August 20, 2020)
10.41 Amendment No. 8 to Credit Agreement, dated as of October 8, 2020, among Southwestern Energy Company, the lenders party thereto and JP Morgan Chase Bank, N.A., as administrative agent for the lenders (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed October 8, 2020)
10.42* Amendment No. 9 to Credit Agreement, dated as of December 11, 2020 among Southwestern Energy Company, JPMorgan Chase Bank N.A., as Administrative Agent, and each lender from time to time party thereto
10.43 Support Agreement, dated as of August 12, 2020, by and among certain stockholders affiliated with EnCap Investments L.P. and Southwestern Energy Company (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on August 12, 2020)
10.44 Retirement and Consulting Agreement dated June 4, 2020 by and between Southwestern Energy Company and John C. Ale. (Incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K (Commission File No. 1-08246) filed June 4, 2020)
21.1* List of Subsidiaries
23.1* Consent of PricewaterhouseCoopers LLP
23.2* Consent of Netherland, Sewell & Associates, Inc.
31.1* Certification of CEO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2* Certification of CFO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1* Certification of CEO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2* Certification of CFO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
95.1* Mine Safety Disclosure
99.1* Reserve Audit Report of Netherland, Sewell & Associates, Inc., dated February 9, 2021
101.1* Interactive Data Files Pursuant to Rule 405 of Regulation S-T, formatted in Inline XBRL: (i) Consolidated Statements of Operations for the three years ended December 31, 2020, (ii) Consolidated Statements of Comprehensive Income for the three years ended December 31, 2020, (iii) Consolidated Balance Sheets as of December 31, 2020 and 2019, (iv) Consolidated Statements of Cash Flows for the three years ended December 31, 2020, (v) Consolidated Statements of Changes in Equity for the three years ended December 31, 2020 and (vi) Notes to Consolidated Financial Statements
104.1* The cover page from the Company's Annual Report on Form 10-K for the year ended December 31, 2020, formatted in Inline XBRL (included in Exhibit 101)
______________ * Filed herewith
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below details our natural gas firm transportation, firm sales and total takeaway capacity over the next three years as of February 25, 2021:
<img src='content_image/1046353.jpg'>
(1) We have extension options and potential contract renewal capacity of 76,900 MMBtu per day for 2022 and 76,900 MMBtu per day for 2023 for Southwest Appalachia.
## Demand Charges
As of December 31, 2020, our obligations for demand and similar charges under the firm transportation agreements and gathering agreements totaled approximately $8.5 billion, $531 million of which related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and additional construction efforts. We also have guarantee obligations of up to $923 million of that amount. In February 2020, we were notified that the proposed Constitution pipeline project was cancelled and that we were released from a firm transportation agreement with its sponsor.
In the first quarter of 2019, we agreed to purchase firm transportation with pipelines in Appalachia starting in 2021 and running through 2032 totaling $357 million in total contractual commitments, of which the seller has agreed to reimburse us for $133 million.
We refer you to Note 10 to the consolidated financial statements included in this Annual Report for further details on our demand charges and the risk factor “We have made significant investments in oilfield services businesses, including our drilling rigs, water infrastructure and pressure pumping equipment, to lower costs and secure inputs for our operations and transportation for our production. If our development and production activities are curtailed or disrupted, we may not recover our investment in these activities, which could adversely impact our results of operations. In addition, our continued expansion of these operations may adversely impact our relationships with third-party providers” in Item 1A of Part I of this Annual Report.
## Competition
Our marketing activities compete with numerous other companies offering the same services, many of which possess larger financial and other resources than we have. Some of these competitors are other producers and affiliates of companies with extensive pipeline systems that are used for transportation from producers to end users. Other factors affecting competition are the cost and availability of alternative fuels, the level of consumer demand and the cost of and proximity to pipelines and other transportation facilities. We believe that our ability to compete effectively within the marketing segment in the future depends upon establishing and maintaining strong relationships with customers.
## Customers
Our marketing customers include major energy companies, utilities and industrial purchasers of natural gas. For the year ended December 31, 2020, one purchaser accounted for 10% of our revenues. A default could have a material impact on the Company, but we do not believe that there is a material risk of default. No other purchasers accounted for greater than 10% of consolidated revenues. During the year ended December 31, 2019, no single third-party purchaser accounted for 10% or more of our consolidated revenues. We believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, oil and NGL production.
## Regulation
The transportation of natural gas, oil and NGLs is heavily regulated. FERC regulates the rates and the terms and conditions of transportation service provided by interstate natural gas, crude oil and NGL pipelines. State governments typically must authorize the construction of pipelines for intrastate service. Moreover, the rates charged for intrastate transportation by pipeline are subject to regulation by state regulatory commissions. The basis for intrastate pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate pipeline rates, varies from state to state. Currently, all pipelines we own are intrastate and immaterial to our operations.
State and local permitting, zoning and land use regulations can affect the location, construction and operation of gathering and other pipelines needed to transport production to market, and the lack of new pipeline capacity can limit our ability to reach relevant markets for the sale of the commodities we produce.
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## Index to Financial Statements
The transportation of natural gas and oil is also subject to extensive environmental regulation. We refer you to “Other – Environmental Regulation” in Item 1 of Part I of this Annual Report and the risk factor “We, our service providers and our customers are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities” in Item 1A of Part I of this Annual Report for a discussion of the impact of environmental regulation on our business.
## Other
We currently have no significant business activity outside of our E&P and Marketing segments.
## Environmental Regulation
General. Our operations are subject to environmental regulation in the jurisdictions in which we operate. These laws and regulations require permits for drilling wells and the maintenance of bonding requirements to drill or operate wells, and also regulate the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the prevention and cleanup of pollutants and other matters. We maintain insurance for clean-up costs in limited instances arising out of sudden and accidental events, but otherwise we may not be fully insured against all such risks. Although future environmental obligations are not expected to have a material impact on the results of our operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.
Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties and the imposition of injunctive relief. Certain laws and legal principles can make us liable for environmental damage to properties we previously owned, and although we generally require purchasers to assume that liability, there is no assurance that they will have sufficient funds should a liability arise. Changes in environmental laws and regulations occur frequently, and any changes may result in more stringent and costly waste handling, storage, transportation, disposal or cleanup requirements. We do not expect continued compliance with existing requirements to have a material adverse impact on us, but there can be no assurance that this will continue in the future. We refer you to “Other – Environmental Regulation” in Item 1 of Part 1 of this Annual Report and the risk factor “We, our service providers and our customers are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities” in Item 1A of Part I of this Annual Report for a discussion of the impact of environmental regulation on our business.
The following is a summary of the more significant existing environmental and worker health and safety laws and regulations to which we are subject.
Generation and Disposal of Wastes. The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, also known as CERCLA or the “Superfund law,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current or former owner or operator of a site where the release occurred, as well as persons that transported or disposed, or arranged for the transportation or disposal of, the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
The Resource Conservation and Recovery Act, as amended, or RCRA, generally does not regulate wastes generated by the exploration and production of natural gas and oil. RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil, natural gas or geothermal energy.” However, legislative and regulatory initiatives have been considered from time to time that would reclassify certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If such measures were to be enacted, it could have a significant impact on our operating costs. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.
The Clean Water Act, as amended, or CWA, and analogous state laws, impose restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into regulated waters. Permits must be obtained to discharge pollutants to regulated waters and to conduct construction activities in waters and wetlands. The CWA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges
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This Annual Report on Form 10-K (“Annual Report”) includes certain statements that may be deemed to be “forward-looking” within the meaning of Section 27A of the Securities Act of 1933, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, or the Exchange Act. We refer you to “Risk Factors” in Item 1A of Part I and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Annual Report for a discussion of factors that could cause actual results to differ materially from any such forward-looking statements. The electronic version of this Annual Report, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those forms filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available free of charge as soon as reasonably practicable after they are filed with the Securities and Exchange Commission, or SEC, on our website at www.swn.com. Our corporate governance guidelines and the charters of the Audit, the Compensation, the Health, Safety, Environment and Corporate Responsibility and the Nominating and Governance Committees of our Board of Directors are available on our website and, upon request, in print free of charge to any stockholder. Information on our website is not incorporated into this report.
We file periodic reports, current reports and proxy statements with the SEC electronically. The SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address of the SEC’s website is www.sec.gov. The public may also read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC- 0330.
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of reportable quantities of oil and other hazardous substances. The EPA has adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans.
The Oil Pollution Act, as amended, or OPA, and regulations promulgated thereunder impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills into regulated waters. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages. Although liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by OPA. OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Although oil accounted for only 4% of our total production in 2020 and 2019 and 2% in 2018, we expect this percentage to increase as we continue to develop our Southwest Appalachia assets.
We own or lease, and have in the past owned or leased, onshore properties that for many years have been used for or associated with the exploration for and production of natural gas and oil. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us and/or on or under other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of wastes was not under our control. Under CERCLA, the CWA, RCRA and analogous state laws, we could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators), or to perform remedial plugging or closure operations to prevent future contamination.
Air Emissions. The Clean Air Act, as amended, restricts emissions into the atmosphere. Various activities we conduct as part of our operations, such as drilling, pumping and the use of vehicles, can result in emissions to the environment. We must obtain permits, typically from local authorities, to conduct various regulated activities. Federal and state governmental agencies are looking into the issues associated with methane and other emissions from oil and natural gas activities, and further regulation could increase our costs or restrict our ability to produce. Although methane emissions are not currently regulated at the federal level, we are required to report emissions of various greenhouse gases, including methane.
Threatened and Endangered Species. The Endangered Species Act and comparable state laws protect species threatened with possible extinction. Protection of threatened and endangered species may have the effect of prohibiting or delaying us from obtaining drilling and other permits and may include restrictions on road building and other activities in areas containing the affected species or their habitats. Based on the species that have been identified to date, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our operations at this time.
Hydraulic Fracturing. We utilize hydraulic fracturing in drilling wells as a means of maximizing their productivity. It is an essential and common practice in the oil and gas industry used to stimulate the production of oil, natural gas, and associated liquids from dense and deep rock formations. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow the flow of hydrocarbons into the wellbore.
In the past several years, there has been an increased focus on the environmental aspects of hydraulic fracturing, both in the United States and abroad. In the United States, hydraulic fracturing is typically regulated by state oil and natural gas commissions, but federal agencies have started to assert regulatory authority over certain aspects of the process. For example, the Environmental Protection Agency, or EPA, issued final rules effective as of October 15, 2012 that subject oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAP programs. In May 2016, the EPA finalized additional regulations to control methane and volatile organic compound (“VOC”) emissions from certain oil and gas equipment and operations. In September 2018, the EPA issued proposed revisions to those regulations, which would reduce certain obligations thereunder. In September 2020, the EPA finalized further amendments to the standards that removed the transmission and storage segments from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. Several lawsuits were filed challenging these amendments, and the U.S. Court of Appeals for the D.C. Circuit ordered an administrative stay of these amendments shortly after they were finalized. Although the administrative stay was lifted in October 2020, which brought the amendments into effect, the amendments may be subject to reversal under a new presidential administration. As a result, we cannot predict the scope of any final methane regulatory requirements or the cost to
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Mr. Huggins has served as Vice President of Commercial and Business Development since March 2018. Prior to that he served in various operational and technical leadership roles since joining the Company in 2007.
Mrs. Gillenwater was appointed Vice President of Human Resources in June 2018. Prior to joining the Company, she served as Global Vice President of Human Resources at Nabors Industries and Vice President of Human Resources at Smith International / Schlumberger Ltd.
There are no family relationships between any of the Company’s directors or executive officers.
## GLOSSARY OF CERTAIN INDUSTRY TERMS
The definitions set forth below include indicated terms in this Annual Report. All natural gas reserves reported in this Annual Report are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit. All currency amounts are in U.S. dollars unless specified otherwise.
“Acquisition of properties” Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties. For additional information, see the SEC’s definition in Rule 4-10(a) (1) of Regulation S-X, a link for which is available at the SEC’s website.
“Available reserves” Estimates of the amounts of natural gas, oil and NGLs which the registrant can produce from current proved developed reserves using presently installed equipment under existing economic and operating conditions and an estimate of amounts that others can deliver to the registrant under long-term contracts or agreements on a per-day, per-month, or per-year basis. For additional information, see the SEC’s definition in Item 1207(d) of Regulation S-K, a link for which is available at the SEC’s website.
“Basis differential” The difference in price for a commodity between a market index price and the price at a specified location.
“Bbl” One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
“Bcf” One billion cubic feet of natural gas.
“Bcfe” One billion cubic feet of natural gas equivalent. Determined using the ratio of one barrel of oil or natural gas liquids to six Mcf of natural gas.
“Btu” One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
“Deterministic estimate” The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure. For additional information, see the SEC’s definition in Rule 4-10(a) (5) of Regulation S-X, a link for which is available at the SEC’s website.
“Developed oil and gas reserves” Developed oil and natural gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
For additional information, see the SEC’s definition in Rule 4-10(a) (6) of Regulation S-X, a link for which is available at the SEC’s website.
“Development costs” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing natural gas, oil and NGLs. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
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(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
(iv) Provide improved recovery systems.
For additional information, see the SEC’s definition in Rule 4-10(a) (7) of Regulation S-X, a link for which is available at the SEC’s website.
“Development project” A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project. For additional information, see the SEC’s definition in Rule 4-10(a) (8) of Regulation S-X, a link for which is available at the SEC’s website.
“Development well” A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. For additional information, see the SEC’s definition in Rule 4-10(a) (9) of Regulation S-X, a link for which is available at the SEC’s website.
“E&P” Exploration for and production of natural gas, oil and NGLs.
“Economically producible” The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities. For additional information, see the SEC’s definition in Rule 4-10(a) (10) of Regulation S-X, a link for which is available at the SEC’s website.
“Estimated ultimate recovery (EUR)” Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date. For additional information, see the SEC’s definition in Rule 4-10(a) (11) of Regulation S-X, a link for which is available at the SEC’s website.
“Exploitation” The development of a reservoir to extract its natural gas and/or oil.
“Exploratory well” An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section. For additional information, see the SEC’s definition in Rule 4-10(a) (13) of Regulation S-X, a link for which is available at the SEC’s website.
“Field” An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. For additional information, see the SEC’s definition in Rule 4- 10(a) (15) of Regulation S-X, a link for which is available at the SEC’s website.
“Gross well or acre” A well or acre in which the registrant owns a working interest. The number of gross wells is the total number of wells in which the registrant owns a working interest. For additional information, see the SEC’s definition in Item 1208(c)(1) of Regulation S-K, a link for which is available at the SEC’s website.
“Gross working interest” Gross working interest is the working interest in a given property plus the proportionate share of any royalty interest, including overriding royalty interest, associated with the working interest.
“Henry Hub” A common market pricing point for natural gas in the United States, located in Louisiana.
“Hydraulic fracturing” A process whereby fluids mixed with proppants are injected into a wellbore under pressure in order to fracture, or crack open, reservoir rock, thereby allowing oil and/or natural gas trapped in the reservoir rock to travel through the fractures and into the well for production.
“Infill drilling” Drilling wells in between established producing wells to increase recovery of natural gas, oil and NGLs from a known reservoir.
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## Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging in the face of shifting market conditions, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition and reduce our future growth rate.
We necessarily must consider future price and cost environments when deciding how much capital we are likely to have available from net cash flow and how best to allocate it. Our current philosophy is to generally operate within cash flow from operations, net of changes in working capital, and to invest capital in a portfolio of projects that are projected to generate the highest combined Internal Rate of Return. Volatility in prices and potential errors in estimating costs, reserves or timing of production of the reserves can result in uneconomic projects or economic projects generating less than anticipated returns.
## Certain of our undeveloped assets are subject to leases that will expire over the next several years unless production is established on units containing the acreage.
Approximately 19,242 and 68,825 net acres of our Northeast Appalachia and Southwest Appalachia acreage, respectively, will expire in the next three years if we do not drill successful wells to develop the acreage or otherwise take action to extend the leases. Our ability to drill wells depends on a number of factors, including certain factors that are beyond our control, such as the ability to obtain permits on a timely basis or to compel landowners or lease holders on adjacent properties to cooperate. Further, we may not have sufficient capital to drill all the wells necessary to hold the acreage without increasing our debt levels, or given price projections at the time, drilling may not be projected to achieve a sufficient return or be judged to be the best use of our capital. To the extent we do not drill the wells, our rights to acreage can be lost.
## Natural gas and oil drilling and producing and transportation operations can be hazardous and may expose us to liabilities.
Drilling and production operations are subject to many risks, including well blowouts, cratering and explosions, pipe failures, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, severe weather, natural disasters, groundwater contamination and other environmental hazards and risks. Some of these risks or hazards could materially and adversely affect our revenues and expenses by reducing or shutting in production from wells, loss of equipment or otherwise negatively impacting the projected economic performance of our prospects. If any of these risks occurs, we could sustain substantial losses as a result of:
• injury or loss of life;
• severe damage to or destruction of property, natural resources or equipment;
• pollution or other environmental damage;
• clean-up responsibilities;
• regulatory investigations and administrative, civil and criminal penalties; and
• injunctions resulting in limitation or suspension of operations.
For our properties that we do not operate, we depend on the operator for operational and regulatory compliance.
We rely on third parties to transport our production to markets. Their operations, and thus our ability to reach markets, are subject to all of the risks and operational hazards inherent in transporting natural gas and ethane and natural gas compression, including:
• damages to pipelines, facilities and surrounding properties caused by third parties, severe weather, natural disasters, including hurricanes, and acts of terrorism;
• maintenance, repairs, mechanical or structural failures;
• damages to, loss of availability of and delays in gaining access to interconnecting third-party pipelines;
• disruption or failure of information technology systems and network infrastructure due to various causes, including unauthorized access or attack; and
• leaks of natural gas or ethane as a result of the malfunction of equipment or facilities.
A material event such as those described above could expose us to liabilities, monetary penalties or interruptions in our business operations. Although we may maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities, and our insurance does not cover penalties or fines that may be
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assessed by a governmental authority. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase.
## We have made significant investments in oilfield service businesses, including our drilling rigs, water infrastructure and pressure pumping equipment, to lower costs and secure inputs for our operations and transportation for our production. If our development and production activities are curtailed or disrupted, we may not recover our investment in these activities, which could adversely impact our results of operations. In addition, our continued expansion of these operations may adversely impact our relationships with third-party providers.
We also have made investments to meet certain of our field services’ needs, including establishing our own drilling rig operation, water transportation system in Southwest Appalachia and pressure pumping capability. If our level of operations is reduced for a long period, we may not be able to recover these investments. Further, our presence in these service and supply sectors, including competing with them for qualified personnel and supplies, may have an adverse effect on our relationships with our existing third-party service and resource providers or our ability to secure these services and resources from other providers.
## Our business depends on the availability of water and the ability to dispose of water. Limitations or restrictions on our ability to obtain or dispose of water may have an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of drilling and hydraulic fracturing processes. Limitations or restrictions on our ability to secure sufficient amounts of water, or to dispose of or recycle water after use, could adversely impact our operations. In some cases, water may need to be obtained from new sources and transported to drilling sites, resulting in increased costs. Moreover, the introduction of new environmental initiatives and regulations related to water acquisition or waste water disposal, including produced water, drilling fluids and other wastes associated with the exploration, development or production of hydrocarbons, could limit or prohibit our ability to utilize hydraulic fracturing or waste water injection control wells.
In addition, concerns have been raised about the potential for seismic activity to occur from the use of underground injection control wells, a predominant method for disposing of waste water from oil and gas activities. New rules and regulations may be developed to address these concerns, possibly limiting or eliminating the ability to use disposal wells in certain locations and increasing the cost of disposal in others. We utilize third parties to dispose of waste water associated with our operations. These third parties may operate injection wells and may be subject to regulatory restrictions relating to seismicity.
Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of water necessary for hydraulic fracturing of wells or the disposal of water may increase our operating costs or may cause us to delay, curtail or discontinue our exploration and development plans, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
## Our producing properties are concentrated in the Appalachian basin, making us vulnerable to risks associated with operating in limited geographic areas.
Our producing properties currently are geographically concentrated in the Appalachian basin in Pennsylvania, West Virginia and Ohio. At December 31, 2020, nearly 100% of our total estimated proved reserves were attributable to properties located in the Appalachian basin. As a result of this concentration in one primary region, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, state and local politics, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or interruption of the processing or transportation of natural gas, oil or NGLs.
## Competition in the oil and natural gas industry is intense, making it more difficult for us to market natural gas, oil and NGLs, to secure trained personnel and appropriate services, to obtain additional properties and to raise capital.
Our cost of operations is highly dependent on third-party services, and competition for these services can be significant, especially in times when commodity prices are rising. Similarly, we compete for trained, qualified personnel, and in times of lower prices for the commodities we produce, we and other companies with similar production profiles may not be able to attract and retain this talent. Our ability to acquire and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing natural gas, oil and NGLs and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and gas industry. Certain of our competitors may possess and employ financial, technical and personnel resources greater than ours. Those companies may be able to pay more for personnel, property and services and to attract capital at lower rates. This may become more likely if prices for oil and NGLs increase faster than prices for natural gas, as natural gas comprises a greater percentage of our overall production than it does for most of the companies with whom we compete for talent.
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Although Congress from time to time has considered legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of adopted legislation to reduce greenhouse gas emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of states, including states in which we operate, have enacted or passed measures to track and reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and regional greenhouse gas cap-and-trade programs. Most of these cap-and-trade programs require major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall greenhouse gas emission reduction goal is achieved. These reductions may cause the cost of allowances to escalate significantly over time.
The adoption and implementation of regulations that require reporting of greenhouse gases or otherwise limit emissions of greenhouse gases from our equipment and operations could require us to incur costs to monitor and report on greenhouse gas emissions or install new equipment to reduce emissions of greenhouse gases associated with our operations. In addition, these regulatory initiatives could drive down demand for our products by stimulating demand for alternative forms of energy that do not rely on combustion of fossil fuels that serve as a major source of greenhouse gas emissions, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. At the same time, new laws and regulations are prompting power producers to shift from coal to natural gas, which is increasing demand.
In December 2015, over 190 countries, including the United States, reached an agreement to reduce global greenhouse gas emissions (the “Paris Agreement”). The Paris Agreement entered into force in November 2016 after more than 70 nations, including the United States, ratified or otherwise indicated their intent to be bound by the agreement. In November 2019, the United States formally initiated the process for withdrawing from the Paris Agreement, which resulted in an effective exit date of November 2020. However, in January 2021, the new administration announced that the United States intends to rejoin the Paris Agreement. To the extent that the United States and other countries implement this agreement or impose other climate change regulations on the oil and natural gas industry, or that investors insist on compliance regardless of legal requirements, it could have an adverse effect on our business.
## We, our service providers and our customers are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.
Our development and production operations and the transportation of our products to market are subject to complex and stringent federal, state and local laws and regulations, including those governing environmental protection, the occupational health and safety aspects of our operations, the discharge of materials into the environment, and the protection of certain plant and animal species. See “Other – Environmental Regulation” in Item 1 of Part I of this Annual Report for a description of the laws and regulations that affect us. These laws and regulations require us, our service providers and our customers to obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Environmental regulations may restrict the types, quantities and concentration of materials that may be released into the environment in connection with drilling and production activities, limit or prohibit drilling or transportation activities on certain lands lying within wilderness, wetlands, archeological sites and other protected areas, and impose substantial liabilities for pollution resulting from our operations and those of our service providers and customers. Moreover, we or they may experience delays in obtaining or be unable to obtain required permits, including as a result of government shutdowns, which may delay or interrupt our or their operations and limit our growth and revenues. In addition, various officials and candidates at the federal, state and local levels, including some presidential candidates, have proposed banning hydraulic fracturing altogether.
Failure to comply with laws and regulations can trigger a variety of administrative, civil and criminal enforcement measures, including investigatory actions, the assessment of monetary penalties, the imposition of remedial requirements, or the issuance of orders or judgments limiting or enjoining future operations. Strict liability or joint and several liability may be imposed under certain laws, which could cause us to become liable for the conduct of others or for consequences of our own actions. Moreover, our costs of compliance with existing laws could be substantial and may increase or unforeseen liabilities could be imposed if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. If we are not able to recover the increased costs through insurance or increased revenues, our business, financial condition, results of operations and cash flows could be adversely affected.
Risks Related to Financial Markets and Uncertainties
## Market views of our industry generally can affect our stock price.
Factors described elsewhere, including views regarding future commodity prices, regulation and climate change, can affect the amount investors choose to invest in our industry generally. Recent years have seen a significant reduction in overall investment in exploration and production companies, resulting in a drop in individual companies’ stock prices. Separate from actual and possible governmental action, certain financial institutions have announced policies to cease investing or to divest
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## Our commodity price risk management and measurement systems and economic hedging activities might not be effective and could increase the volatility of our results.
We currently seek to hedge the price of a significant portion of our estimated production through swaps, collars, floors and other derivative instruments. The systems we use to quantify commodity price risk associated with our businesses might not always be effective. Further, such systems do not in themselves manage risk, particularly risks outside of our control, and adverse changes in energy commodity market prices, volatility, adverse correlation of commodity prices, the liquidity of markets, changes in interest rates and other risks discussed in this report might still adversely affect our earnings, cash flows and balance sheet under applicable accounting rules, even if risks have been identified. Furthermore, no single hedging arrangement can adequately address all risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist.
Our use of derivatives, through which we attempt to reduce the economic risk of our participation in commodity markets could result in increased volatility of our reported results. Changes in the fair values (gains and losses) of derivatives that qualify as hedges under GAAP to the extent that such hedges are not fully effective in offsetting changes to the value of the hedged commodity, as well as changes in the fair value of derivatives that do not qualify or have not been designated as hedges under GAAP, must be recorded in our income. This creates the risk of volatility in earnings even if no economic impact to us has occurred during the applicable period. To the extent we cap or lock prices at specific levels, we would also forgo the ability to realize the higher revenues that would be realized should prices increase.
The impact of changes in market prices for natural gas, oil and NGLs on the average prices paid or received by us may be reduced based on the level of our hedging activities. These hedging arrangements may limit or enhance our margins if the market prices for oil, natural gas or NGLs were to change substantially from the price established by the hedges. In addition, our hedging arrangements expose us to the risk of financial loss if our production volumes are less than expected.
## The implementation of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The Dodd-Frank Act established federal oversight and regulation of the over-the-counter derivatives market and entities, including us, which participate in that market. The Dodd-Frank Act requires the CFTC, the SEC, and other regulatory authorities to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized most of its regulations under the Dodd-Frank Act, it continues to review and refine its initial rulemakings through additional interpretations and supplemental rulemakings. As a result, it is not possible at this time to predict the ultimate effect of the rules and regulations on our business and while most of the regulations have been adopted, any new regulations or modifications to existing regulations may increase the cost of derivative contracts, limit the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and the regulations thereunder, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital investing.
In January 2020, the CFTC proposed new amended regulations that would place federal limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. In 2016, the CFTC finalized a companion rule on aggregation of positions among entities under common ownership or control. If finalized, the position limits rule may have an impact on our ability to hedge our exposure to certain enumerated commodities.
The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and mandatory trading on designated contract markets or swap execution facilities. The CFTC may designate additional classes of swaps as subject to the mandatory clearing requirement in the future, but has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. The CFTC and prudential banking regulators also adopted mandatory margin requirements on uncleared swaps between swap dealers and certain other counterparties. The margin requirements are currently effective with respect to certain market participants and will be phased in over time with respect to other market participants, based on the level of an entity’s swaps activity. We expect to qualify for and rely upon an end-user exception from the mandatory clearing and trade execution requirements for swaps entered to hedge our commercial risks. We also should qualify for an exception from the uncleared swaps margin requirements. However, the application of the mandatory clearing and trade execution requirements and the uncleared swaps margin requirement to other market participants, such as swap dealers, may adversely affect the cost and availability of the swaps that we use for hedging.
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The information regarding oil and gas production, production prices and production costs required by Item 1204 of Regulation S-K is set forth below:
## Production, Average Sales Price and Average Production Cost
<img src='content_image/1028178.jpg'>
(1) The Fayetteville Shale E&P assets and associated reserves were sold in December 2018.
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## ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis is the Company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures included elsewhere in this report. It contains forward-looking statements including, without limitation, statements relating to the Company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. In many cases you can identify forward-looking statements by words such as “anticipate,” “intend,” “plan,” “project,” “estimate,” “continue,” “potential,” “should,” “could,” “may,” “will,” “objective,” “guidance,” “outlook,” “effort,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “forecast,” “target” or similar words. Unless required to do so under the federal securities laws, the Company does not undertake to update, revise or correct any forward-looking statements, whether as a result of new information, future events or otherwise. Readers are cautioned that such forward-looking statements should be read in conjunction with the Company’s disclosures under the heading: “ Cautionary Statement about Forward- Looking Statements .”
## Background
## OVERVIEW
Southwestern Energy Company (including its subsidiaries, collectively, “we,” “our,” “us,” “the Company” or “Southwestern”) is an independent energy company engaged in natural gas, oil and NGLs exploration, development and production, which we refer to as “E&P.” We are also focused on creating and capturing additional value through our marketing business, which we call “Marketing”. We conduct most of our businesses through subsidiaries, and we currently operate exclusively in the lower 48 United States.
E&P. Our primary business is the exploration for and production of natural gas, oil and NGLs, with our ongoing operations focused on the development of unconventional natural gas reservoirs located in Pennsylvania, Ohio and West Virginia. Our operations in northeast Pennsylvania, which we refer to as “Northeast Appalachia,” are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale. Our operations in West Virginia, Ohio and southwest Pennsylvania, which we refer to as “Southwest Appalachia,” are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs. Collectively, our properties in Pennsylvania, Ohio and West Virginia are herein referred to as “Appalachia.” We also have drilling rigs located in Appalachia, and we provide certain oilfield products and services, principally serving our E&P operations though vertical integration.
On November 13, 2020, we closed on our Agreement and Plan of Merger (the “Merger agreement”) with Montage Resources Corporation (“Montage”) pursuant to which Montage merged with and into Southwestern, with Southwestern continuing as the surviving company (the “Merger”). The Merger expanded our footprint in Appalachia by supplementing our Northeast Appalachia and Southwest Appalachia operations and by expanding our operations into Ohio. See Note 3 to the consolidated financial statements of this Annual Report for more information on the Merger.
Marketing. Our marketing activities capture opportunities that arise through the marketing and transportation of natural gas, oil, and NGLs primarily produced in our E&P operations.
Focus in 2020. We entered 2020 with a continued focus on optimizing our cost structure, maximizing margins in each of our core areas of business while further developing our knowledge of our asset base and looking for strategic transactions that take advantage of our core strengths. The recent Merger and the associated expected cost and operational synergies is a reflection of this strategy. While COVID-19 brought challenges of lower demand for certain of our products resulting in lower oil and NGL pricing (discussed below), we exercised our capital and operational agility by quickly shifting our investments to our higher return natural gas assets. We remained committed to our focus on creating sustainable value with the goal of generating cash flow above and beyond our operational needs, while at the same time maintaining our leading position as stewards of the environment. We continued to protect our financial strength through bond repurchases at a discount as well as a robust derivative program designed to ensure certain cash flow levels by reducing our exposure to commodity price volatility.
Lower natural gas, oil and NGL prices present challenges to our industry and our Company, as do changes in laws, regulations and investor sentiment and other key factors described under “Risk Factors” in Item 1A of this Annual Report. During the year ended December 31, 2020, the economic impact of the COVID-19 pandemic and related governmental and societal measures (discussed below), along with the disagreements between OPEC and Russia on production levels, caused oil prices to decrease significantly in the first and second quarters of 2020. While oil pricing partially recovered late in the second quarter and continued to improve toward the end of the year, gains on our settled derivatives offset a large portion of the impact of the overall decline in prices. Although we currently expect to maintain a robust rolling three-year derivative portfolio, there can be no
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## Production Volumes
<img src='content_image/1048483.jpg'>
(1) Approximately 878 Bcfe and 776 Bcfe for the years ended December 31, 2020 and 2019, respectively, were produced from the Marcellus Shale formation.
• Production volumes for our E&P segment increased 102 Bcfe for the year ended December 31, 2020, compared to the same period in 2019, primarily due to a 28% increase in production volumes in Southwest Appalachia.
• Oil and NGL production increased 9% and 10%, respectively, for the year ended December 31, 2020, compared to 2019.
## Commodity Prices
The price we expect to receive for our production is a critical factor in determining the capital investments we make to develop our properties. Commodity prices fluctuate due to a variety of factors we can neither control nor predict, including increased supplies of natural gas, oil or NGLs due to greater exploration and development activities, weather conditions, political and economic events such as the response to the COVID- 19 pandemic, and competition from other energy sources. These factors impact supply and demand, which in turn determine the sales prices for our production. In addition to these factors, the prices we realize for our production are affected by our hedging activities as well as locational differences in market prices, including basis differentials. We will continue to evaluate the commodity price environments and adjust the pace of our activity in order to maintain appropriate liquidity and financial flexibility.
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We refer you to Note 11 to the consolidated financial statements included in this Annual Report for additional discussion about our income taxes.
## LIQUIDITY AND CAPITAL RESOURCES
We depend primarily on funds generated from our operations, our 2018 credit facility, our cash and cash equivalents balance and capital markets as our primary sources of liquidity. In October 2020, the banks participating in our 2018 credit facility reaffirmed our elected borrowing base and aggregate commitments to be $1.8 billion. Upon the closing of the Merger in November 2020 and satisfaction of related conditions, the elected borrowing base and total aggregate commitments increased from $1.8 billion to $2.0 billion, the maximum permitted lien amount based on provisions in certain of our senior notes indentures. As of February 25, 2021, we had approximately $1.3 billion of total available liquidity, which exceeds our currently modeled needs, and looking forward in 2021, we remain committed to our strategy of free cash flow generation through capital discipline. We refer you to Note 9 to the consolidated financial statements included in this Annual Report and the section below under “Credit Arrangements and Financing Activities” for additional discussion of our 2018 credit facility and related covenant requirements.
Our cash flow from operating activities is highly dependent upon our ability to sell and the sales prices that we receive for our natural gas and liquids production. Natural gas, oil and NGL prices are subject to wide fluctuations and are driven by market supply and demand, which is impacted by many factors. See "Market Conditions and Commodity Prices" in the Overview section of Item 7 in Part II for additional discussion about current and potential future market conditions. The sales price we receive for our production is also influenced by our commodity derivative program. Our derivative contracts allow us to ensure a certain level of cash flow to fund our operations. In 2020, $362 million in realized gains on derivatives have offset a large portion of the impact of lower commodity prices, and although we are continually adding additional derivative positions for portions of our expected 2021, 2022 and 2023 production, there can be no assurance that we will be able to add derivative positions to cover the remainder of our expected production at favorable prices. See “Risk Factors” in Item 1A, “ Quantitative and Qualitative Disclosures about Market Risk ” in Item 7A and Note 6 in the consolidated financial statements included in this Annual Report for further details.
Our commodity hedging activities are subject to the credit risk of our counterparties being financially unable to settle the transaction. We actively monitor the credit status of our counterparties, performing both quantitative and qualitative assessments based on their credit ratings and credit default swap rates where applicable, and to date have not had any credit defaults associated with our transactions. However, any future failures by one or more counterparties could negatively impact our cash flow from operating activities.
Our short-term cash flows are also dependent on the timely collection of receivables from our customers and joint interest owners. We actively manage this risk through credit management activities and, through the date of this filing, have not experienced any significant write-offs for non- collectable amounts. However, any sustained inaccessibility of credit by our customers and joint interest owners could adversely impact our cash flows.
Due to these factors, we are unable to forecast with certainty our future level of cash flow from operations. Accordingly, we expect to adjust our discretionary uses of cash depending upon available cash flow. Further, we may from time to time seek to retire, rearrange or amend some or all of our outstanding debt or debt agreements through cash purchases, and/or exchanges, open market purchases, privately negotiated transactions, tender offers or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
## Credit Arrangements and Financing Activities
In April 2018, we replaced our credit facility entered into in 2016 with a new revolving credit facility (the "2018 credit facility") with a group of banks that, as amended, has a maturity date of April 2024. The 2018 credit facility has an aggregate maximum revolving credit amount of $3.5 billion and, in October 2020, the banks participating in our 2018 credit facility reaffirmed the borrowing base to be $1.8 billion, which also reflected our aggregate commitments. Upon the closing of the Merger in November 2020, the borrowing base and total aggregate commitments were increased from $1.8 billion to $2.0 billion. The borrowing base is subject to redetermination at least twice a year, in April and October, and is subject to change based primarily on drilling results, commodity prices, our future derivative position, the level of capital investment and operating costs. On October 8, 2020, we entered into an amendment to the credit agreement governing the 2018 credit facility to, among other matters, limit our unrestricted cash and cash equivalents to $200 million when loans under the 2018 credit facility are outstanding, subject to certain exceptions, and to increase the applicable rate by 25 basis points on loans outstanding under the 2018 credit facility. The 2018 credit facility is secured by substantially all of our assets, including most of our subsidiaries. The permitted lien provisions in certain senior note indentures currently limit liens securing indebtedness to the greater of $2.0 billion or 25% of
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Our reserve estimates and the after-tax PV-10 measure, or standardized measure of discounted future net cash flows relating to proved natural gas, oil and NGL reserve quantities, are highly dependent upon the respective commodity price used in our reserve and after-tax PV-10 calculations.
• Our reserves decreased 6% in 2020, compared to 2019, primarily due to a decrease in commodity pricing, partially offset by the reserves acquired from Montage.
• Our after-tax PV-10 value decreased in 2020 compared to 2019 as lower reserve levels resulted primarily from a decrease in SEC 12-month backward-looking commodity prices.
• We are the designated operator of approximately 97% of our reserves, based on the pre-tax PV-10 value of our proved developed producing reserves, and our reserve life index was approximately 11.3 years at year-end 2020, using an estimate of full year production from our recently acquired Montage properties.
The following table presents the PV-10 value of our reported year-end 2020 reserves balance using SEC 12-month backward-looking prices and the 12-month forward-looking strip prices as of January 4, 2021:
<img src='content_image/1030925.jpg'>
(1) Adjusted for market differentials.
The difference in after-tax PV-10 and pre-tax PV-10 (a non-GAAP measure which is reconciled in the 2020 Proved Reserves by Category and Summary Operating Data table below) is the discounted value of future income taxes on the estimated cash flows. Our existing tax attributes, including net operating losses and remaining depreciable tax basis related to our natural gas and oil properties, more than offset our future net operating income, resulting in no tax effect to our PV-10 calculation for the year ended December 31, 2020.
We believe that the pre-tax PV-10 value of the estimated cash flows related to our estimated proved reserves is a useful supplemental disclosure to the after-tax PV-10 value. Pre-tax PV-10 is based on prices, costs and discount factors that are comparable from company to company, while the after-tax PV-10 is dependent on the unique tax situation of each individual company. We understand that securities analysts use pre-tax PV-10 as one measure of the value of a company’s current proved reserves and to compare relative values among peer companies without regard to income taxes. We refer you to “ Supplemental Oil and Gas Disclosures ” in Item 8 of Part II of this Annual Report for a discussion of our standardized measure of discounted future cash flows related to our proved natural gas, oil and NGL reserves, to the risk factor “Our proved natural gas, oil and NGL reserves are estimates that include uncertainties. Any material change to these uncertainties or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A of Part I of this Annual Report, and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Annual Report for a discussion of the risks inherent in utilization of standardized measures and estimated reserve data.
Lower natural gas, oil and NGL prices reduce the value of our assets, both by a direct reduction in what the production could be sold for and by making some properties uneconomic, resulting in decreases to the overall value of our reserves and potential non-cash impairment charges to earnings. Further non-cash impairments in future periods could occur if the trailing 12-month commodity prices decrease as compared to the average used in prior periods.
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(1) Includes $9 million and $35 million for the years ended December 31, 2020 and 2019, respectively, related to our water infrastructure project.
<img src='content_image/1032234.jpg'>
Actual capital expenditure levels may vary significantly from period to period due to many factors, including drilling results, natural gas, oil and NGL prices, industry conditions, the prices and availability of goods and services, and the extent to which properties are acquired or non-strategic assets are sold.
Cash Flow from Financing Activities
• Net cash provided by financing activities for the year ended December 31, 2020 was $361 million, compared to net cash used in financing activities of $115 million for the same period in 2019.
• In August 2020, we completed debt and equity offerings resulting in $345 million and $152 million in net proceeds, respectively.
• In November 2020, we paid $522 million to retire the Montage senior notes, and repaid the outstanding balance of $200 million related to Montage’s revolving credit facility.
• In 2020, we repurchased $107 million in aggregate principal amount of our outstanding senior notes at a discount for $72 million and recognized a $35 million gain on the extinguishment of debt.
• In 2019, we paid $54 million on the open market to repurchase $62 million of our outstanding senior notes at a discount. We recognized a gain on early extinguishment of debt of $8 million.
• In December 2019, we retired the remaining $52 million principal of our 4.05% Senior Notes due January 2020.
• In January 2019, we repurchased approximately 5 million shares of common stock for approximately $21 million.
We refer you to Note 9 to the consolidated financial statements included in this Annual Report for additional discussion of our outstanding debt and credit facility and to Note 1 for additional discussion of our equity offering.
## Working Capital
• We had negative working capital of $341 million at December 31, 2020, a $172 million decrease from December 31, 2019, as an $8 million increase in cash and cash equivalents was more than offset by a $70 million increase in various payables and a $157 million net reduction in the current mark-to-market value of our derivative position related to improved forward strip pricing across all commodities as compared to December 2019. Additionally, other current liabilities at December 31, 2020 decreased $34 million, compared to December 31, 2019, as a $43 million decrease in our accrued firm transportation liability related to the Fayetteville Shale sale was only partially offset by a prepayment that we received for an unrelated firm transportation assumption. We believe that our existing cash and cash equivalents, our anticipated cash flow from operations and our available credit facility will be sufficient to meet our working capital and operational spending requirements.
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allegations and the damage theories have not been fully developed, and are all subject to inherent uncertainties; therefore, management’s view may change in the future.
We are also subject to laws and regulations relating to the protection of the environment. Environmental and cleanup related costs of a non- capital nature are accrued when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on our financial position, results of operations or cash flows.
For further information, we refer you to “Litigation” and “Environmental Risk” in Note 10 to the consolidated financial statements included in this Annual Report.
## Supplemental Guarantor Financial Information
As discussed in Note 9 , in April 2018 the Company entered into the 2018 credit facility. Pursuant to requirements under the indentures governing our senior notes, each 100% owned subsidiary that became a guarantor of the 2018 credit facility also became a guarantor of each of our senior notes (the “Guarantor Subsidiaries”). The Guarantor Subsidiaries also granted liens and security interests to support their guarantees under the 2018 credit facility but not of the senior notes. These guarantees are full and unconditional and joint and several among the Guarantor Subsidiaries. Certain of our operating units which are accounted for on a consolidated basis do not guarantee the 2018 credit facility and senior notes.
Upon the November 2020 closing of the Merger with Montage, certain Montage entities owning oil and gas properties became guarantors to the 2018 credit facility.
The Company and the Guarantor Subsidiaries jointly and severally, and fully and unconditionally, guarantee the payment of the principal and premium, if any, and interest on the senior notes when due, whether at stated maturity of the senior notes, by acceleration, by call for redemption or otherwise, together with interest on the overdue principal, if any, and interest on any overdue interest, to the extent lawful, and all other obligations of the Company to the holders of the senior notes.
SEC Regulation S-X Rule 13-01 requires the presentation of “Summarized Financial Information” to replace the “Condensed Consolidating Financial Information” required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantors are not materially different than the corresponding amounts presented in the consolidated financial statements of the Company. The Parent and Guarantor Subsidiaries comprise the material operations of the Company. Therefore, the Company concluded that the presentation of the Summarized Financial Information is not required as the Summarized Financial Information of the Company’s Guarantors is not materially different from our consolidated financial statements.
## CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The discussion and analysis of financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires management to make estimates and judgments that affect the amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. We evaluate our estimates on an on-going basis, based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following describes significant judgments and estimates used in the preparation of our consolidated financial statements.
## Natural Gas and Oil Properties
We utilize the full cost method of accounting for costs related to the exploration, development and acquisition of natural gas and oil properties. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities, are capitalized on a country-by-country basis and amortized over the estimated lives of the properties using the units- of-production method. These capitalized costs are subject to a quarterly ceiling test that limits such pooled costs, net of applicable deferred taxes, to the aggregate of the present value of future net revenues attributable to proved natural gas, oil and NGL reserves discounted at 10% (standardized measure) plus the lower of cost or market value of unproved properties. Any costs in excess of the ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas, oil and NGL prices may subsequently increase the ceiling. Companies using the full cost method are required to use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives designated for hedge accounting, to calculate the ceiling value of their reserves.
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Costs associated with unevaluated properties are excluded from our amortization base until we have evaluated the properties or impairment is indicated. The costs associated with unevaluated leasehold acreage and related seismic data, wells currently drilling and related capitalized interest are initially excluded from our amortization base. Leasehold costs are either transferred to our amortization base with the costs of drilling a well on the lease or are assessed at least annually for possible impairment or reduction in value. Our decision to withhold costs from amortization and the timing of the transfer of those costs into the amortization base involves judgment and may be subject to changes over time based on several factors, including our drilling plans, availability of capital, project economics and drilling results from adjacent acreage. At December 31, 2020, we had approximately $1,472 million of costs excluded from our amortization base, all of which related to our properties in the United States. Inclusion of some or all of these costs in our properties in the United States in the future, without adding any associated reserves, could result in non-cash ceiling test impairments.
At December 31, 2020, the ceiling value of our reserves was calculated based upon the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $1.98 per MMBtu, for West Texas Intermediate oil of $39.57 per barrel and NGLs of $10.27 per barrel, adjusted for market differentials. The net book value of our natural gas and oil properties exceeded the ceiling amount in each quarter of 2020 resulting in total non-cash full cost ceiling test write-downs of $2,825 million. We had no derivative positions that were designated for hedge accounting as of December 31, 2020. Future decreases in market prices, as well as changes in production rates, levels of reserves, evaluation costs excluded from amortization, future development costs and production costs may result in further non-cash impairments to our natural gas and oil properties.
No impairment expense was recorded for the year ended December 31, 2020 in relation to our recently acquired Montage natural gas and oil properties. These properties were recorded at fair value as of November 13, 2020, in accordance with ASC 820 Fair Value Measurement . Pursuant to SEC guidance, we determined that the fair value of the properties acquired at the closing of the Merger clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received a waiver from the SEC to exclude the properties acquired in the Merger from the ceiling test calculation. This waiver was granted for all reporting periods through and including the quarter ending September 30, 2021 as long as we can continue to demonstrate that the fair value of properties acquired clearly exceeds the full cost ceiling limitation beyond a reasonable doubt in each reporting period. As part of the waiver received from the SEC, we are required to disclose what the full cost ceiling test impairment amounts for all periods presented in each applicable quarterly and annual filing would have been if the waiver had not been granted. The fair value of the properties acquired in the Merger was based on forward strip natural gas and oil pricing existing at the date of the Merger, and we affirmed that there has not been a material decline to the fair value of these acquired assets since the Merger. The properties acquired in the Merger have an unamortized cost at December 31, 2020 of $1,087 million. Had we not received the waiver from the SEC, the impairment charge recorded would have been an additional $539 million for the year ended December 31, 2020.
Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.58 per MMBtu, West Texas Intermediate oil of $55.69 per barrel and NGLs of $11.58 per barrel, adjusted for market differentials, the net book value of our United States natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at December 31, 2019. We had no derivative positions that were designated for hedge accounting as of December 31, 2019.
Changes in natural gas, oil and NGL prices used to calculate the discounted future net revenues of our reserves affects both the present value of cash flows and the quantity of reserves. Our reserve base as of December 31, 2020 was approximately 76% natural gas, 3% NGLs and 21% oil, and our standardized measure and reserve quantities as of December 31, 2020, were $1.85 billion and 12.0 Tcfe, respectively.
Proved natural gas, oil and NGL reserves are a major component of the full cost ceiling test. Natural gas, oil and NGL reserves cannot be measured exactly. Our estimate of natural gas, oil and NGL reserves requires extensive judgments of reservoir engineering data and projections of costs that will be incurred in developing and producing reserves and is generally less precise than other estimates made in connection with financial disclosures. Our reservoir engineers prepare our reserve estimates under the supervision of our management. Reserve estimates are prepared for each of our properties annually by the reservoir engineers assigned to the asset management team for that property. The reservoir engineering and financial data included in these estimates are reviewed by senior engineers, who are not part of the asset management teams, and by our Director of Reserves, who is the technical person primarily responsible for overseeing the preparation of our reserves estimates. Our Director of Reserves has more than 26 years of experience in petroleum engineering, including the estimation of natural gas and oil reserves, and holds a Bachelor of Science in Petroleum Engineering. Prior to joining us in 2018, our Director of Reserves served in various reservoir engineering roles for EP Energy Company, El Paso Corporation, Cabot Oil & Gas Corporation, Schlumberger and H.J. Gruy & Associates, and is a member of the Society of Petroleum Engineers. He reports to our Executive Vice President and Chief Operating Officer, who has more than 32 years of experience in petroleum engineering including the estimation of natural gas, oil and NGL reserves in multiple basins in the United States, and holds a Bachelor of Science in Petroleum Engineering. Prior to
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joining Southwestern in 2017, our Chief Operating Officer served in various engineering and leadership roles for EP Energy Corporation, El Paso Corporation, ARCO Oil and Gas Company, Burlington Resources and Peoples Energy Production, and is a member of the Society of Petroleum Engineers.
We engage NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies, to independently audit our proved reserves estimates as discussed in more detail below. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. Within NSAI, the two technical persons primarily responsible for auditing our proved reserves estimates (1) have over 23 years and over 19 years of practical experience in petroleum geosciences and petroleum engineering, respectively; (2) have over 12 years and over 19 years of experience in the estimation and evaluation of reserves, respectively; (3) each has a college degree; (4) each is a Licensed Professional Geoscientist in the State of Texas or a Licensed Professional Engineer in the State of Texas; (5) each meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; and (6) each is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. The financial data included in the reserve estimates is also separately reviewed by our accounting staff. Our proved reserves estimates, as internally reviewed and audited by NSAI, are submitted for review and approval to our President and Chief Executive Officer. Finally, upon his approval, NSAI reports the results of its reserve audit to the Board of Directors, with whom final authority over the estimates of our proved reserves rests. A copy of NSAI’s report has been filed as Exhibit 99.1 to this Annual Report.
Proved developed reserves generally have a higher degree of accuracy in this estimation process, when compared to proved undeveloped and proved non-producing reserves, as production history and pressure data over time is available for the majority of our proved developed properties. Proved developed reserves accounted for 68% of our total reserve base as of December 31, 2020. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. The uncertainties inherent in the reserve estimates are compounded by applying additional estimates of the rates and timing of future production volumes and the costs that will be incurred in developing and producing the reserves. We cannot assure you that our internal controls sufficiently address the numerous uncertainties and risks that are inherent in estimating quantities of natural gas, oil and NGL reserves and projecting future rates of production and timing of development expenditures as many factors are beyond our control. We refer you to “Our proved natural gas, oil and NGL reserves are estimates that include uncertainties. Any material changes to these uncertainties or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A , “Risk Factors,” of Part I of this Annual Report for a more detailed discussion of these uncertainties, risks and other factors.
In conducting its audit, the engineers and geologists of NSAI study our major properties in detail and independently develop reserve estimates. NSAI’s audit consists primarily of substantive testing, which includes a detailed review of major properties that account for approximately 97% of the present worth of the company’s total proved reserves. NSAI’s audit process consists of sorting all fields by descending present value order and selecting the fields from highest value to descending value until the selected fields account for more than 80% of the present worth of our reserves. The fields included in approximately the top 99% present value as of December 31, 2020, accounted for approximately 99% of our total proved reserves and approximately 100% of our proved undeveloped reserves. In the conduct of its audit, NSAI did not independently verify the data we provided to them with respect to ownership interests, natural gas, oil and NGL production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. NSAI has advised us that if, in the course of its audit, something came to its attention that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved any questions relating thereto or had independently verified such information or data. On February 9, 2021, NSAI issued its audit opinion as to the reasonableness of our reserve estimates for the year-ended December 31, 2020 stating that our estimated proved natural gas, oil and NGL reserves are, in the aggregate, reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
## Business Combinations
We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. Fair value of proved natural gas and oil properties as of the acquisition date was based on estimated proved natural gas, oil and NGL reserves and related discounted net cash flows. Significant inputs to the valuation include estimates of future production volumes, future operating and development costs, future
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commodity prices and a weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, we review comparable purchases and sales of natural gas and oil properties within the same regions, and use that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties. Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities.
The Merger with Montage qualified as a business combination, and as such, we estimated the fair value of the assets acquired and liabilities assumed as of the November 13, 2020 acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of natural gas and oil reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as defined in Note 8 – Fair Value Measurements. We recorded the net assets acquired and liabilities assumed in the Montage Merger at their estimated fair value of approximately $213 million, which we consider to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized.
## Derivatives and Risk Management
We use fixed price swap agreements and options to reduce the volatility of earnings and cash flow due to fluctuations in the prices of certain commodities and interest rates. Our policies prohibit speculation with derivatives and limit agreements to counterparties with appropriate credit standings to minimize the risk of uncollectability. We actively monitor the credit status of our counterparties based on their credit ratings and credit default swap rates where applicable, and to date have not had any credit defaults associated with our transactions. In 2020 and 2019, we financially protected 83% and 69%, respectively, of our total production with derivatives. The primary risks related to our derivative contracts are the volatility in market prices and basis differentials for our production. However, the market price risk is generally offset by the gain or loss recognized upon the related transaction that is financially protected.
All derivatives are recognized in the balance sheet as either an asset or a liability as measured at fair value other than transactions for which the normal purchase/normal sale exception is applied. Certain criteria must be satisfied for derivative financial instruments to be designated for hedge accounting. Accounting guidance for qualifying hedges allows an unsettled derivative’s unrealized gains and losses to be recorded in either earnings or as a component of other comprehensive income until settled. In the period of settlement, we recognize the gains and losses from these qualifying hedges in gas sales revenues. The ineffective portion of those fixed price swaps are recognized in earnings. Gains and losses on derivatives that are not designated for hedge accounting treatment, or that do not meet hedge accounting requirements, are recorded as a component of gain (loss) on derivatives on the consolidated statements of operations. Accordingly, the gain (loss) on derivatives component of the statement of operations reflects the gains and losses on both settled and unsettled derivatives. We calculate gains and losses on settled derivatives as the summation of gains and losses on positions which have settled within the reporting period.
As of December 31, 2020, none of our derivative contracts were designated for hedge accounting treatment. Changes in the fair value of unsettled derivatives that were not designated for hedge accounting treatment are recorded in gain (loss) on derivatives. See Note 6 to the consolidated financial statements included in this Annual Report for more information on our derivative position at December 31, 2020.
Future market price volatility could create significant changes to the derivative positions recorded in our consolidated financial statements. We refer you to “ Quantitative and Qualitative Disclosures about Market Risk ” in Item 7A of Part II of this Annual Report for additional information regarding our hedging activities.
## Pension and Other Postretirement Benefits
We record our prepaid or accrued benefit cost, as well as our periodic benefit cost, for our pension and other postretirement benefit plans using measurement assumptions that we consider reasonable at the time of calculation (see Note 13 to the consolidated financial statements included in this Annual Report for further discussion and disclosures regarding these benefit plans). Two of the assumptions that affect the amounts recorded are the discount rate, which estimates the rate at which benefits could be effectively settled, and the expected return on plan assets, which reflects the average rate of earnings expected on the funds invested. For the December 31, 2020 benefit obligation the initial discount rate assumed is 3.10%. This compares to an initial discount rate of 3.70% for the benefit obligation and periodic benefit cost recorded in 2020. As part of ongoing effort to reduce costs, we have elected to freeze our pension plan effective January 1, 2021. Employees that were participants in the
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pension plan prior to January 1, 2021 will continue to receive the interest component of the plan but will no longer receive the service component. For the 2021 periodic benefit cost, the expected return assumed was reduced from 6.50% to 5.10%.
Using the assumed rates discussed above, we recorded total benefit cost of $9 million in 2020 related to our pension and other postretirement benefit plans. Due to the significance of the discount rate and expected long-term rate of return, the following sensitivity analysis demonstrates the effect that a 0.5% change in those assumptions would have had on our 2020 pension expense:
<img src='content_image/1028575.jpg'>
As of December 31, 2020, we recognized a liability of $46 million, compared to $43 million at December 31, 2019, related to our pension and other postretirement benefit plans. During 2020, we made cash contributions totaling $13 million to fund our pension and other postretirement benefit plans.
## Long-term Incentive Compensation
Our long-term incentive compensation plans consist of a combination of stock-based awards that derive their value directly or indirectly from our common stock price, and cash-based awards that are fixed in amount, but subject to meeting annual performance thresholds. In March 2020, we issued our first long-term fixed cash-based awards.
We account for long-term incentive compensation transactions using a fair value method and recognize an amount equal to the fair value of the stock-based awards and cash-based awards cost in either the consolidated statement of operations or capitalize the cost into natural gas and oil properties included in property and equipment. Costs are capitalized when they are directly related to the acquisition, exploration and development activities of our natural gas and oil properties. We use models to determine fair value of stock-based compensation, which requires significant judgment with respect to forfeitures, volatility and other factors. The performance cash awards granted in 2020 include a performance condition determined annually by the Company. If we, in our sole discretion, determine that the threshold was not met, the amount for that vesting period will not vest and will be cancelled.
Our stock-based compensation is classified as either an equity award or a liability award in accordance with generally accepted accounting principles. The fair value of an equity-classified award is determined at the grant date and is amortized on a straight-line basis over the vesting life of the award. The fair-value of a liability-classified award is determined on a quarterly basis through the final vesting date and is amortized based on the current fair value of the award and the percentage of vesting period incurred to date. See Note 14 to the consolidated financial statements included in this Annual Report for further discussion and disclosures regarding our long-term incentive compensation.
## New Accounting Standards
Refer to Note 1 to the consolidated financial statements included in this Annual Report for further discussion of our significant accounting policies and for discussion of accounting standards that have been implemented in this report, along with a discussion of relevant accounting standards that are pending adoption.
## CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
All statements, other than historical fact or present financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance. We have no obligation and make no undertaking to publicly update or revise any forward- looking statements, except as may be required by law.
Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Annual Report identified by words such as “anticipate,” “intend,” “plan,” “project,” “estimate,” “continue,” “potential,” “should,” “could,” “may,” “will,” “objective,” “guidance,” “outlook,” “effort,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “forecast,” “model,” “target” or similar words. Statements may be forward-looking even in the absence of these particular words.
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You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:
• the timing and extent of changes in market conditions and prices for natural gas, oil and NGLs (including regional basis differentials) and the impact of reduced demand for our production and products in which our production is a component due to governmental and societal actions taken in response to the COVID-19 or other pandemic;
• our ability to fund our planned capital investments;
• a change in our credit rating, an increase in interest rates and any adverse impacts from the discontinuation of the London Interbank Offered Rate (“LIBOR”);
• the extent to which lower commodity prices impact our ability to service or refinance our existing debt;
• the impact of volatility in the financial markets or other global economic factors, including the impact of COVID-19 or other diseases;
• difficulties in appropriately allocating capital and resources among our strategic opportunities;
• the timing and extent of our success in discovering, developing, producing and estimating reserves;
• our ability to maintain leases that may expire if production is not established or profitably maintained;
• our ability to realize the expected benefits from acquisitions, including the Merger;
• costs in connection with the Merger;
• integration of operations and results subsequent to the Merger;
• our ability to transport our production to the most favorable markets or at all;
• availability and costs of personnel and of products and services provided by third parties;
• the impact of government regulation, including changes in law, the ability to obtain and maintain permits, any increase in severance or similar taxes, and legislation or regulation relating to hydraulic fracturing or other drilling and completing techniques, climate and over-the-counter derivatives;
• the impact of the adverse outcome of any material litigation against us or judicial decisions that affect us or our industry generally;
• the effects of weather or power outages;
• increased competition;
• the financial impact of accounting regulations and critical accounting policies;
• the comparative cost of alternative fuels;
• credit risk relating to the risk of loss as a result of non-performance by our counterparties; and
• any other factors listed in the reports we have filed and may file with the SEC.
Should one or more of the risks or uncertainties described above or elsewhere in this Annual Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to update publicly any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.
All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.
## ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risks relating to our operations result primarily from the volatility in commodity prices, basis differentials and interest rates, as well as service costs and credit risk concentrations. We use fixed price swap agreements, options, swaptions, basis swaps and interest rate swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas, oil and certain NGLs along with interest rates. Our Board of Directors has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price risk. Utilization of financial products for the reduction of interest rate risks is also overseen by our Board of Directors. These policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings.
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## SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
<img src='content_image/1020605.jpg'>
(1) In 2018, deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.
(2) Net of $1 million and $2 million in taxes for the years ended December 31, 2020 and 2019, respectively.
(3) Net of ($2) million and ($1) million in taxes for the year ended December 31, 2020 and 2019, respectively.
The accompanying notes are an integral part of these consolidated financial statements.
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## SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
<img src='content_image/1046438.jpg'>
The accompanying notes are an integral part of these consolidated financial statements.
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## SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
<img src='content_image/1055846.jpg'>
The accompanying notes are an integral part of these consolidated financial statements.
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## (1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
## Nature of Operations
## SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Southwestern Energy Company (including its subsidiaries, collectively “Southwestern” or the “Company”) is an independent energy company engaged in natural gas, oil and NGLs exploration, development and production (“E&P”). The Company is also focused on creating and capturing additional value through its marketing business (“Marketing”), which was previously referred to as “Midstream” when it included the operations of gathering systems. Southwestern conducts most of its business through subsidiaries and operates principally in two segments: E&P and Marketing.
E&P. Southwestern’s primary business is the exploration for and production of natural gas, oil and NGLs, with ongoing operations focused on the development of unconventional natural gas and oil reservoirs located in Pennsylvania, Ohio and West Virginia. The Company’s operations in northeast Pennsylvania, herein referred to as “Northeast Appalachia,” are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale. Operations in West Virginia, Ohio and southwest Pennsylvania, herein referred to as “Southwest Appalachia,” are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs. Collectively, Southwestern refers to its properties located in Pennsylvania, Ohio and West Virginia as “Appalachia.” The Company also operates drilling rigs located in Appalachia, and provides oilfield products and services, principally serving the Company's E&P operations through vertical integration.
In August 2020, the Company entered into an Agreement and Plan of Merger (the "Merger Agreement") with Montage Resources Corporation ("Montage") pursuant to which Montage will merge with and into Southwestern, with Southwestern continuing as the surviving company (the "Merger"). The Company acquired at the effective time of the merger all of the outstanding shares of common stock in Montage in exchange for 1.8656 shares of Southwestern common stock per share of Montage common stock. The transaction closed on November 13, 2020. The Merger expanded the Company's footprint in Appalachia by supplementing the Northeast Appalachia and Southwest Appalachia operations and by expanding the Company's operations into Ohio. See Note 3 for more information about the Merger.
Marketing. Southwestern’s marketing activities capture opportunities that arise through the marketing and transportation of natural gas, oil and NGLs primarily produced in its E&P operations.
## Basis of Presentation
The consolidated financial statements included in this Annual Report present the Company’s financial position, results of operations and cash flows for the periods presented in accordance with accounting principles generally accepted in the United States (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The Company evaluates subsequent events through the date the financial statements are issued.
## Principles of Consolidation
The consolidated financial statements include the accounts of Southwestern and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.
In 2015, the Company purchased an 86% ownership in a limited partnership that owns and operates a gathering system in Northeast Appalachia. Because the Company owns a controlling interest in the partnership, the operating and financial results are consolidated with the Company’s E&P segment results. The minority partner’s share of the partnership activity is reported in retained earnings in the consolidated financial statements. Net income attributable to noncontrolling interest for the years ended December 31, 2020, 2019 and 2018 was insignificant.
## Major Customers
The Company sells the vast majority of its E&P natural gas, oil and NGL production to third-party customers through its marketing subsidiary. Customers include major energy companies, utilities and industrial purchasers of Natural gas. For the year ended December 31, 2020, one purchaser accounted for 10% of total revenues. A default on this account could have a material impact on the Company, but the Company does not believe that there is a material risk of default. No other purchasers accounted for greater than 10% of consolidated revenues. For the year ended December 31, 2019, no single customer accounted for 10% or greater of total sales. The Company believes that the loss of any one customer would not have an adverse effect on its ability to sell its natural gas, oil and NGL production.
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(6) Pre-tax PV-10 (a non-GAAP measure) is one measure of the value of a company’s proved reserves that we believe is used by securities analysts to compare relative values among peer companies without regard to income taxes. The reconciling difference in pre-tax PV-10 and the after-tax PV-10, or standardized measure, is the discounted value of future income taxes on the estimated cash flows from our proved natural gas, oil and NGL reserves. Our existing tax attributes, including net operating losses and remaining depreciable tax basis related to our natural gas and oil properties, more than offset our future net operating income, resulting in no tax effect to our PV-10 calculation for the year ended December 31, 2020.
(7) Includes future asset retirement obligations outside of Appalachia.
(8) Based upon pre-tax PV-10 of proved developed producing activities.
## Lease Expirations
The following table summarizes the leasehold acreage expiring over the next three years, assuming successful wells are not drilled to develop the acreage and leases are not extended:
<img src='content_image/1034442.jpg'>
(1) We have no reported proved undeveloped locations expiring in 2021.
(2) The leasehold acreage expiring includes 8,907 acres acquired through the Montage Merger that are subject to annual extension options at our sole discretion. Excluding this acreage, of the remaining leasehold acreage expiring, 17,460 net acres in 2021, 6,173 net acres in 2022 and 5,573 net acres in 2023 can be extended for an average 4.9 years.
(3) Exploration licenses were extended through March 2021 but have been subject to a moratorium since 2015. We are currently working with Canadian officials to extend our licenses, although we cannot assure that the licenses will be extended past March 2021. We fully impaired our investment in New Brunswick in 2016.
We refer you to “Supplemental Oil and Gas Disclosures” in Item 8 of Part II of this Annual Report for a more detailed discussion of our proved natural gas, oil and NGL reserves as well as our standardized measure of discounted future net cash flows related to our proved natural gas, oil and NGL reserves. We also refer you to the risk factor “Our proved natural gas, oil and NGL reserves are estimates that include uncertainties. Any material changes to these uncertainties or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A of Part I of this Annual Report and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Annual Report for a discussion of the risks inherent in utilization of standardized measures and estimated reserve data.
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and annual footnote disclosures, however, the adoption of ASU 2018 is not expected to have a material impact on the Company's consolidated financial statements.
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform, as a new Accounting Standards Codification (“ASC”) Topic, ASC 848. The purpose of ASC 848 is to provide optional guidance to ease the potential effects on financial reporting of the market-wide migration away from Interbank Offered Rates, such as LIBOR, which is expected to be phased out at the end of calendar year 2021, to alternative reference rates. ASC 848 applies only to contracts, hedging relationships, debt arrangements and other transactions that reference a benchmark reference rate expected to be discontinued because of reference rate reform. ASC 848 contains optional expedients and exceptions for applying U.S. GAAP to transactions affected by this reform. The amendments in the ASU are effective for all entities as of March 12, 2020 through December 31, 2022. The Company is currently assessing the impact of adopting this new guidance.
## (2) RESTRUCTURING CHARGES
As part of an ongoing strategic effort to reposition its portfolio, optimize operational performance and improve margins, the Company has incurred charges related to restructuring that include reductions in workforce, office consolidation and other costs, including those associated with the sale of a large asset such as the Fayetteville Shale. These charges are further discussed below. The following table presents a summary of the restructuring charges included in Operating Income for the years ended December 31, 2020, 2019 and 2018:
<img src='content_image/1021259.jpg'>
(1) Does not include a $4 million gain for the year ended December 31, 2018 related to curtailment of the other postretirement benefit plan presented in other income (loss), net on the consolidated statements of operations.
The following table presents a summary of liabilities associated with the Company’s restructuring activities at December 31, 2020, which are reflected in accounts payable on the consolidated balance sheet:
<img src='content_image/1021260.jpg'>
## Reduction in Workforce (Not Fayetteville Shale Sale-Related)
In February 2020, the Company notified employees of a workforce reduction plan as a result of a strategic realignment of the Company's organizational structure. This reduction was substantially complete by the end of the first quarter of 2020. Affected employees were offered a severance package, which included a one-time payment depending on length of service and, if applicable, the current value of unvested long-term incentive awards that were forfeited. These costs were recognized as restructuring charges for the year ended December 31, 2020. The Company also recognized additional severance costs in the fourth quarter of 2020 related to continued organizational restructuring for which a liability of $3 million has been accrued as of December 31, 2020.
In June 2018, the Company notified affected employees of a workforce reduction plan, which resulted primarily from a previously announced study of structural, process and organizational changes to enhance shareholder value and continues with respect to other aspects of the Company’s business activities. Affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, the current value of a portion of equity awards that were forfeited.
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[
"content_image/1030632.jpg",
"content_image/1030633.jpg"
] |
overall_image/1b7494c2f5082df1f9f01f47abb15aecea25676a21c4ac9e9d365e7cdd2002a4.png
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The following table presents a summary of the restructuring charges related to workforce reduction plans included in Operating Income (Loss) for the year ended December 31, 2020, 2019 and 2018:
<img src='content_image/1030632.jpg'>
(1) Total restructuring charges were $16 million for the Company's E&P segment for the year ended December 31, 2020. Total restructuring charges for the Company's E&P and Marketing segments were $21 million and $2 million, respectively, for the year ended December 31, 2018.
## Fayetteville Shale Sale-Related
In December 2018, the Company closed on the sale of the equity in certain of its subsidiaries that owned and operated its Fayetteville Shale E&P and related midstream gathering assets in Arkansas. As part of this transaction, most employees associated with those assets became employees of the buyer although the employment of some was terminated. All affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, the current value of a portion of equity awards that were forfeited. The Company had substantially completed the Fayetteville Shale sale-related employment terminations by December 31, 2019.
As a result of the Fayetteville Shale sale, the Company relocated certain employees and infrastructure to other locations and began the process of consolidating and reorganizing its office space. Approximately $2 million in charges related to office consolidation and reorganization were recognized as restructuring charges.
In July 2019, the Company terminated its existing lease agreement in its headquarters office building and entered into a new 10-year lease agreement for a smaller portion of the building. Approximately $3 million of the fees associated with the Company’s headquarters office consolidation and $1 million in other office consolidation expenses are reflected as restructuring charges for the year ended December 31, 2019. The Company also recognized additional severance costs in the third and fourth quarters of 2019, related to continued organizational restructuring. The following table presents a summary of the restructuring charges related to the consolidation and reorganization associated with the Fayetteville Shale sale included in Operating Income on the condensed statements of operations for the years ended December 31, 2019 and 2018:
<img src='content_image/1030633.jpg'>
(1) Total restructuring charges were $11 million and $16 million for the Company’s E&P segment for the years ended December 31, 2019 and 2018, respectively.
(2) Does not include a $4 million gain for the year ended December 31, 2018 related to the curtailment of the other postretirement benefit plan presented in Other Income (Loss), net on the consolidated statements of operations.
See Note 3 for a discussion of the Company’s Fayetteville Shale sale.
## (3) ACQUISITIONS AND DIVESTITURES
## Montage Resources Merger
On August 12, 2020, Southwestern entered into an Agreement and Plan of Merger with Montage Resources Corporation (“Montage”) whereby Montage would merge with and into Southwestern, with Southwestern continuing as the surviving company (the "Merger"). On November 12, 2020, Montage’s stockholders voted to approve the Merger and it was made effective on November 13, 2020. The Merger added to Southwestern’s oil and gas portfolio in Appalachia.
In exchange for each share of Montage common stock, Montage stockholders received 1.8656 shares of Southwestern common stock, plus cash in lieu of any fractional share of Southwestern common stock that otherwise would have been issued, based on the average price of $3.05 per share of Southwestern common stock on the NYSE on November 13, 2020. Following the closing of the Merger, Southwestern's existing shareholders and Montage's existing shareholders owned approximately 90% and 10%, respectively, of the outstanding shares of the combined company.
In anticipation of the Merger, in August 2020 Southwestern issued $350 million of new senior unsecured notes and 63,250,000 shares of common stock for $152 million after deducting underwriting discounts and offering expenses. The
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## Derivative Liabilities
<img src='content_image/1036838.jpg'>
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(Mark One)
# UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
# FORM 10-K
☒ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
# For the fiscal year ended December 31, 2019
☐ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
(State or other jurisdiction of incorporation or organization)
1 Fountain Square Chattanooga, Tennessee
(Address of principal executive offices)
Delaware
Securities registered pursuant to Section 12(b) of the Act:
Commission file number 001-11294
(Exact name of registrant as specified in its charter)
(Registrant's telephone number, including area code)
For the transition period from to
# Unum Group
(423)294-1011
(I.R.S. Employer Identification No.)
62-1598430
37402
(Zip Code)
<img src='content_image/1034643.jpg'>
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act. Yes [X] No [ ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [X]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes [X] No [ ]
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[] |
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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
(Check one):
Large Accelerated Filer x
Non-accelerated filer ¨
Accelerated filer ☐
Smaller reporting company ☐
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒
The aggregate market value of the shares of the registrant's common stock held by non-affiliates (based upon the closing price of these shares on the New York Stock Exchange) as of the last business day of the registrant's most recently completed second fiscal quarter was $7.0 billion. As of February 14, 2020, there were 202,971,077 shares of the registrant's common stock outstanding.
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[
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Profitability of our supplemental products is affected by persistency, investment returns, claims experience, and the level of administrative expenses.
## Unum Poland
Unum Poland products, which include both individual and group life products, provide renewable term and whole life insurance with accident and health riders. Premiums are based on expected claims of a pool of similar risks plus provisions for administrative expenses, investment income, and profit. Profitability of our Unum Poland products is affected by persistency, investment returns, claims experience, and the level of administrative expenses.
## Colonial Life Segment
Our Colonial Life segment includes accident, sickness, and disability products, which includes our dental and vision products, life products, and cancer and critical illness products. These products are issued primarily by Colonial Life & Accident Insurance Company and marketed to employees, on both a group and an individual basis, at the workplace through an independent contractor agency sales force and brokers. Our market strategy for Colonial Life is to effectively deliver a broad set of voluntary products and services in the public sector market and in the commercial market, with a particular focus on the core commercial market segment, which we define for Colonial Life as accounts with fewer than 1,000 employees.
We have defined underwriting practices and procedures for each of our products. Most policies are issued on a simplified issue basis, based on answers to simple health and employment questions. If the amount applied for exceeds certain levels, the applicant may be asked to answer additional health questions or submit to additional medical examinations.
The percentage of Colonial Life segment premium income generated by each product line during 2019 is as follows:
## Accident, Sickness, and Disability
<img src='content_image/1041653.jpg'>
The accident, sickness, and disability product line consists of short-term disability plans, accident-only plans providing benefits for injuries on a specified loss basis, and our dental and vision products. It also includes accident and health plans covering hospital admissions, confinement, and surgeries.
Premiums for accident, sickness, and disability products are generally based on assumptions for morbidity, mortality, persistency, administrative expenses, investment income, and profit. We develop our assumptions based on our own experience. Premiums are primarily individual guaranteed renewable for which we have the ability to change premiums on a state by state basis. A small percentage of the policies are written on a group basis for which we retain the right to change premiums at the individual account level. Premiums for our dental and vision products are generally guaranteed issue with standard industry rates that vary by age and region. Profitability is affected by the level of employee participation, persistency, investment returns, claims experience, and the level of administrative expenses.
## Life
Life products are primarily comprised of universal life, whole life, and term life policies.
Premium rates vary by age and are based on assumptions concerning mortality, persistency, administrative expenses, investment income, and profit. We develop our assumptions based on our own experience and published industry tables. Premiums for the whole life and level term products are guaranteed for the life of the contract. Premiums for the universal life products are flexible and may vary at the individual policyholder level. For the group term life products, we retain the right to change premiums at the account level based on the experience of the account.
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