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The following table summarizes the gross and net carried reserves for International.
<img src='content_image/1025381.jpg'>
## 2017 Compared with 2016
Net written premiums for International increased $60 million in 2017 as compared with 2016 due to higher new business, positive renewal premium change and higher retention. Excluding the effect of foreign currency exchange rates, net written premiums increased 8.1% in 2017. The increase in net earned premiums was consistent with the trend in net written premiums.
Core income decreased $13 million in 2017 as compared with 2016 driven by lower favorable net prior year loss reserve development and higher net catastrophe losses partially offset by favorable period over period foreign currency exchange results.
The combined ratio of 104.8% increased 5.7 points in 2017 as compared with 2016. The loss ratio increased 6.0 points, primarily due to lower favorable net prior year loss reserve development and higher net catastrophe losses partially offset by lower current accident year large losses. Net catastrophe losses were $64 million, or 7.9 points of the loss ratio, for 2017, as compared with $31 million, or 3.9 points of the loss ratio, for 2016. The loss ratio excluding catastrophes and development improved 3.0 points. The expense ratio improved 0.3 points in 2017 as compared with 2016 primarily due to the higher net earned premiums.
Favorable net prior year loss reserve development of $9 million and $58 million was recorded in 2017 and 2016. Further information on net prior year loss reserve development is in Note E to the Consolidated Financial Statements included under Item 8.
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The following table summarizes policyholder reserves for Life & Group.
<img src='content_image/1032791.jpg'>
<img src='content_image/1032792.jpg'>
(1) To the extent that unrealized gains on fixed income securities supporting long term care products and annuity contracts would result in a premium deficiency if those gains were realized, an increase in Insurance reserves is recorded, net of tax, as a reduction of net unrealized gains through Other comprehensive income (loss) (Shadow Adjustments).
(2) Ceded reserves relate to claim or policy reserves fully reinsured in connection with a sale or exit from the underlying business.
## 2017 Compared with 2016
Core income increased $30 million in 2017 as compared with 2016. This increase was driven by favorable morbidity partially offset by unfavorable persistency in the long term care business. Additionally, the release of long term care claim reserves resulting from the annual claims experience study was higher in 2017 as compared with 2016.
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Agreement). This Agreement has similar terms as the U.S.-E.U. Covered Agreement, and will become effective upon the U.K.'s exit from the E.U.
Because these covered agreements are not self-executing, U.S. state laws will need to be revised to change reinsurance collateral requirements to conform to the provisions within each of the agreements. Before any such revision to state laws can be advanced, the NAIC must develop a new approach for determination of the appropriate reserve credit under statutory accounting for E.U. and U.K. based alien reinsurers. In addition, the NAIC is currently developing an approach to group capital regulation as the current U.S. regulatory regime is based on legal entity regulation. Both the reinsurance collateral requirement change and adoption of group capital regulation must be effected by the states within five years from the signing of the Covered Agreements, or states risk federal preemption. We will monitor the modification of state laws and regulations in order to comply with the provisions of the Covered Agreements and assess potential effects on our operations and prospects.
## Employee Relations
As of December 31, 2018, we had approximately 6,100 employees and have experienced satisfactory labor relations. We have never had work stoppages due to labor disputes.
We have comprehensive benefit plans for substantially all of our employees, including retirement and savings plans, disability programs, group life programs and group health care programs. See Note I to the Consolidated Financial Statements included under Item 8 for further discussion of our benefit plans.
## Available Information
We file annual, quarterly and current reports, proxy statements and other documents with the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934 (Exchange Act). The SEC maintains an internet site that contains reports, proxy and information statements and other information regarding issuers, including CNA. The public can obtain any documents that we file with the SEC at www.sec.gov.
We also make available free of charge on or through our internet website at www.cna.com our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Copies of these reports may also be obtained, free of charge, upon written request to: CNA Financial Corporation, 151 N. Franklin Street, Chicago, IL 60606, Attn: Scott L. Weber, Executive Vice President and General Counsel.
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## INVESTMENTS
## Net Investment Income
The significant components of Net investment income are presented in the following table. Fixed income securities, as presented, include both fixed maturity securities and non-redeemable preferred stock.
<img src='content_image/1040430.jpg'>
Pretax net investment income decreased $217 million in 2018 as compared with 2017. The decrease was driven by limited partnership and common stock investments, which returned (1.9)% in 2018 as compared with 9.1% in the prior year. The lower return in 2018 included the change in fair value of common stock investments. See Note A to the Consolidated Financial Statements included under Item 8 for further information regarding the treatment of the change in fair value of common stock investments. Despite the decline in limited partnership income, net investment income, after tax, increased $38 million in 2018 as compared with 2017 driven by the lower Federal corporate income tax rate.
Pretax net investment income increased $46 million in 2017 as compared with 2016. The increase was driven by limited partnership and common stock investments, which returned 9.1% in 2017 as compared with 6.4% in the prior year.
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## Duration
A primary objective in the management of the investment portfolio is to optimize return relative to the corresponding liabilities and respective liquidity needs. Our views on the current interest rate environment, tax regulations, asset class valuations, specific security issuer and broader industry segment conditions as well as domestic and global economic conditions, are some of the factors that enter into an investment decision. We also continually monitor exposure to issuers of securities held and broader industry sector exposures and may from time to time adjust such exposures based on our views of a specific issuer or industry sector.
A further consideration in the management of the investment portfolio is the characteristics of the corresponding liabilities and the ability to align the duration of the portfolio to those liabilities and to meet future liquidity needs, minimize interest rate risk and maintain a level of income sufficient to support the underlying insurance liabilities. For portfolios where future liability cash flows are determinable and typically long term in nature, we segregate investments for asset/liability management purposes. The segregated investments support the long term care and structured settlement liabilities in the Life & Group segment.
The effective durations of fixed income securities and short term investments are presented in the following table. Amounts presented are net of payable and receivable amounts for securities purchased and sold, but not yet settled.
<img src='content_image/1052064.jpg'>
The investment portfolio is periodically analyzed for changes in duration and related price risk. Additionally, we periodically review the sensitivity of the portfolio to the level of foreign exchange rates and other factors that contribute to market price changes. A summary of these risks and specific analysis on changes is included in the Quantitative and Qualitative Disclosures About Market Risk included under Item 7A.
## Short Term Investments
The carrying value of the components of the Short term investments are presented in the following table.
<img src='content_image/1052063.jpg'>
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## Regulatory Factors
• regulatory and legal initiatives and compliance with governmental regulations and other legal requirements, including with respect to cyber security protocols, legal inquiries by state authorities, judicial interpretations within the regulatory framework, including interpretation of policy provisions, decisions regarding coverage and theories of liability, legislative actions that increase claimant activity, including those revising applicability of statutes of limitations, trends in litigation and the outcome of any litigation involving us and rulings and changes in tax laws and regulations;
• regulatory limitations, impositions and restrictions upon us, including with respect to our ability to increase premium rates, and the effects of assessments and other surcharges for guaranty funds and second-injury funds, other mandatory pooling arrangements and future assessments levied on insurance companies; and
• regulatory limitations and restrictions, including limitations upon our ability to receive dividends from our insurance subsidiaries, imposed by regulatory authorities, including regulatory capital adequacy standards;
## Impact of Catastrophic Events and Related Developments
• weather and other natural physical events, including the severity and frequency of storms, hail, snowfall and other winter conditions, natural disasters such as hurricanes and earthquakes, as well as climate change, including effects on global weather patterns, greenhouse gases, sea, land and air temperatures, sea levels, rain, hail and snow;
• regulatory requirements imposed by coastal state regulators in the wake of hurricanes or other natural disasters, including limitations on the ability to exit markets or to non-renew, cancel or change terms and conditions in policies, as well as mandatory assessments to fund any shortfalls arising from the inability of quasi-governmental insurers to pay claims;
• man-made disasters, including the possible occurrence of terrorist attacks, the unpredictability of the nature, targets, severity or frequency of such events, and the effect of the absence or insufficiency of applicable terrorism legislation on coverages; and
• the occurrence of epidemics.
## Referendum on the United Kingdom's Membership in the European Union
• in 2016, the U.K. approved an exit from the E.U., commonly referred to as "Brexit.” Brexit is scheduled to be completed in early 2019. As treaties between the U.K. and the E.U. have not been finalized, as of January 1, 2019, we intend to write business in the E.U. through our recently established European subsidiary in Luxembourg as our U.K.-domiciled subsidiary will presumably no longer provide a platform for our operations throughout the European continent. As a result of such structural changes and modification to our European operations, the complexity and cost of regulatory compliance of our European business has increased and will likely continue to result in elevated expenses.
Our forward-looking statements speak only as of the date of the filing of this Annual Report on Form 10-K and we do not undertake any obligation to update or revise any forward-looking statement to reflect events or circumstances after the date of the statement, even if our expectations or any related events or circumstances change.
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The following tables present the estimated effects on the fair value of our financial instruments as of December 31, 2018 and 2017 due to an increase in yield rates of 100 basis points, a 10% decline in foreign currency exchange rates and a 10% decline in the S&P 500, with all other variables held constant.
## Market Risk Scenario 1
<img src='content_image/1021785.jpg'>
(1) Reported at amortized value in the Consolidated Balance Sheets included under Item 8 and not adjusted for fair value changes.
## Market Risk Scenario 1
<img src='content_image/1021786.jpg'>
(1) Reported at amortized value in the Consolidated Balance Sheets included under Item 8 and not adjusted for fair value changes.
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## ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
## CNA Financial Corporation
## Consolidated Statements of Operations
## Years ended December 31
<img src='content_image/1020808.jpg'>
The accompanying Notes are an integral part of these Consolidated Financial Statements.
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## CNA Financial Corporation
## Consolidated Statements of Stockholders' Equity
<img src='content_image/1030914.jpg'>
The accompanying Notes are an integral part of these Consolidated Financial Statements.
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of non-redeemable preferred stock and a $4 million increase in the fair value of common stock, both recognized in Other comprehensive income.
ASU 2017-07: In March 2017, the FASB issued ASU No. 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost . The updated accounting guidance requires changes to the presentation of the components of net periodic benefit cost on the income statement by requiring service cost to be presented with other employee compensation costs and other components of net periodic pension cost to be presented outside of any subtotal of operating income. The ASU also stipulates that only the service cost component of net benefit cost is eligible for capitalization. The Company adopted the updated guidance effective January 1, 2018. The guidance was applied on a prospective basis for capitalization of service costs and on a retrospective basis for the presentation of the service cost and other components of net periodic benefit costs in the Company's Consolidated Statements of Operations and in its disclosures. The Company utilized the practical expedient allowing amounts previously disclosed in its Benefit Plans footnote to be used as the estimation basis for prior comparative periods. The Company expanded the related footnote disclosure, Note I to the Consolidated Financial Statements, to disclose the amount of service cost and non-service cost components of net periodic benefit cost and the line items in the Consolidated Statements of Operations in which such amounts are reported. The change limiting the costs eligible for capitalization is not material to the Company’s results of operations or financial position.
ASU 2018-02: In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. GAAP requires the remeasurement of deferred tax assets and liabilities due to a change in the tax rate to be included in Net income, even if the related income tax effects were originally recognized in Accumulated other comprehensive income (AOCI). The ASU allows a reclassification from AOCI to Retained earnings for stranded tax effects resulting from the new U.S. Federal corporate income tax rate enacted on December 22, 2017. The Company early adopted the updated guidance effective January 1, 2018 and elected to reclassify the stranded income tax effects relating to the reduction in the Federal corporate income tax rate from AOCI to Retained earnings at the beginning of the period of adoption. The net impact of the accounting change resulted in a $12 million increase in AOCI and a corresponding decrease in Retained earnings. The $12 million increase in AOCI is comprised of a $142 million increase in net unrealized gains (losses) on investments partially offset by a $130 million decrease in unrecognized pension and postretirement benefits.
The Company releases tax effects from AOCI utilizing the security-by-security approach for Net unrealized gains (losses) on investments with Other-than-temporary impairment (OTTI) losses and Net unrealized gains (losses) on other investments. For Pension and postretirement benefits, tax effects from AOCI are released at enacted tax rates based on the pre-tax adjustments to pension liabilities or assets recognized within OCI.
ASU 2018-13: In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820) Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement. The updated accounting guidance requires changes to the disclosures for fair value measurement by adding, removing and modifying disclosures. This guidance is effective for fiscal years beginning after December 15, 2019, including interim periods therein and early adoption is permitted. As of September 30, 2018, the Company adopted the updated guidance and added disclosures on changes in unrealized gains (losses) on Level 3 assets recognized in Other comprehensive income as well as the weighted average rate used to develop significant inputs utilized in the fair value measurements of Level 3 assets. The Company also eliminated disclosures on the amount of transfers between Level 1 and Level 2 assets and the policy for timing of transfers between Levels.
ASU 2018-14: In August 2018, the FASB issued ASU No. 2018-14, Compensation -Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20) Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans. The updated accounting guidance modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans by removing, modifying and adding disclosures. The guidance is effective for annual periods ending after December 15, 2020, and early adoption is permitted. As of December 31, 2018, the Company adopted the updated accounting guidance by eliminating disclosures of the amounts in AOCI expected to be recognized as part of net periodic cost (benefit) during 2019. The Company also added disclosure of the interest crediting rate used in our defined benefit pension plan and a description of significant gains and losses affecting the benefit obligations for the periods presented.
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indicated the carried reserves were sufficient; therefore, there was no unlocking of assumptions. Interest rates for long term care active life reserves range from 6.6% to 7.0% as of September 30, 2018 and December 31, 2017.
The Company's most recent GPV indicated the future policy benefit reserves for the long term care business were not deficient in the aggregate, but profits are expected to be recognized in early years followed by losses in later years. In that circumstance, future policy benefit reserves are increased in the profitable years by an amount necessary to offset losses that are projected to be recognized in later years. The amount of the additional future policy benefit reserves recorded in each quarterly period is determined by applying the ratio of the present value of future losses divided by the present value of future profits from the most recently completed GPV to long term care core income in that period.
Guaranty fund and other insurance-related assessments: Liabilities for guaranty fund and other insurance-related assessments are accrued when an assessment is probable, when it can be reasonably estimated and when the event obligating the entity to pay an imposed or probable assessment has occurred. Liabilities for guaranty funds and other insurance-related assessments are not discounted and are included as part of Other liabilities on the Consolidated Balance Sheets. As of December 31, 2018 and 2017, the liability balances were $108 million and $121 million.
Reinsurance: Reinsurance accounting allows for contractual cash flows to be reflected as premiums and losses. To qualify for reinsurance accounting, reinsurance agreements must include risk transfer. To meet risk transfer requirements, a reinsurance contract must include both insurance risk, consisting of underwriting and timing risk, and a reasonable possibility of a significant loss for the assuming entity.
Reinsurance receivables related to paid losses are presented at unpaid balances. Reinsurance receivables related to unpaid losses are estimated in a manner consistent with claim and claim adjustment expense reserves or future policy benefit reserves. Reinsurance receivables are reported net of an allowance for uncollectible amounts on the Consolidated Balance Sheets. The cost of reinsurance is primarily accounted for over the life of the underlying reinsured policies using assumptions consistent with those used to account for the underlying policies or over the reinsurance contract period. The ceding of insurance does not discharge the primary liability of the Company.
The Company has established an allowance for uncollectible reinsurance receivables which relates to both amounts already billed on ceded paid losses as well as ceded reserves that will be billed when losses are paid in the future. The allowance for uncollectible reinsurance receivables is estimated on the basis of periodic evaluations of balances due from reinsurers, reinsurer solvency, industry experience and current economic conditions. Reinsurer financial strength ratings are updated and reviewed on an annual basis or sooner if the Company becomes aware of significant changes related to a reinsurer. Because billed receivables generally approximate 5% or less of total reinsurance receivables, the age of the reinsurance receivables related to paid losses is not a significant input into the allowance analysis. Changes in the allowance for uncollectible reinsurance receivables are presented as a component of Insurance claims and policyholders' benefits on the Consolidated Statements of Operations.
Amounts are considered past due based on the reinsurance contract terms. Reinsurance receivables related to paid losses and any related allowance are written off after collection efforts have been exhausted or a negotiated settlement is reached with the reinsurer. Reinsurance receivables from insolvent insurers related to paid losses are written off when the settlement due from the estate can be reasonably estimated. At the time reinsurance receivables related to paid losses are written off, any required adjustment to reinsurance receivables related to unpaid losses is recorded as a component of Insurance claims and policyholders' benefits on the Consolidated Statements of Operations.
Reinsurance contracts that do not effectively transfer the economic risk of loss on the underlying policies are recorded using the deposit method of accounting, which requires that premium paid or received by the ceding company or assuming company be accounted for as a deposit asset or liability. The Company had $3 million and $8 million recorded as deposit assets as of December 31, 2018 and 2017, and $3 million and $4 million recorded as deposit liabilities as of December 31, 2018 and 2017. Income on reinsurance contracts accounted for under the deposit method is recognized using an effective yield based on the anticipated timing of payments and the remaining life of the contract. When the anticipated timing of payments changes, the effective yield is recalculated to reflect actual payments to date and the estimated timing of future payments. The deposit asset or liability is adjusted to the amount that would have existed had the new effective yield been applied since the inception of the contract.
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67,883
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https://cdla.io/permissive-1-0/
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[] |
overall_image/c28974e917b16910f30f99431c0ea42b8910228c83122454ca745d0df12fc045.png
|
## Deferred Non-Insurance Warranty Acquisition Expense
Dealers, retailers and agents earn commission for assisting the Company in obtaining non-insurance warranty contracts. Additionally, the Company utilizes a third-party to perform warranty administrator services for its consumer goods warranties. These costs, which are deferred and recorded as Deferred non-insurance warranty acquisition expense, are amortized to Non-insurance warranty expense consistent with how the related revenue is recognized.
Losses under warranty contracts shall be recognized when it is probable that estimated future costs exceed unrecognized revenue. The Company evaluates deferred costs for recoverability including consideration of anticipated investment income. Adjustments to deferred costs, if necessary, are recorded in the current period results of operations.
## Income Taxes
The Company and its eligible subsidiaries (CNA Tax Group) are included in the consolidated federal income tax return of Loews and its eligible subsidiaries. The Company accounts for income taxes under the asset and liability method. Under the asset and liability method, deferred income taxes are recognized for temporary differences between the financial statement and tax return bases of assets and liabilities, based on enacted tax rates and other provisions of the tax law. The effect of a change in tax laws or rates on deferred tax assets and liabilities is recognized in income in the period in which such change is enacted. Future tax benefits are recognized to the extent that realization of such benefits is more likely than not, and a valuation allowance is established for any portion of a deferred tax asset that management believes will not be realized.
## Pension and Postretirement Benefits
The Company recognizes the overfunded or underfunded status of its defined benefit plans in Other assets or Other liabilities on the Consolidated Balance Sheets. Changes in funded status related to prior service costs and credits and actuarial gains and losses are recognized in the year in which the changes occur through Other comprehensive income. Annual service cost, interest cost, expected return on plan assets, amortization of prior service costs and credits and amortization of actuarial gains and losses are recognized in the Consolidated Statements of Operations. The vested benefit obligation for the CNA Retirement Plan is determined based on eligible compensation and accrued service for previously entitled employees. Effective June 30, 2015, future benefit accruals under the CNA Retirement Plan were eliminated and the benefit obligations were frozen.
## Stock-Based Compensation
The Company records compensation expense using the fair value method for all awards it grants, modifies or cancels primarily on a straight-line basis over the requisite service period, generally three years.
## Foreign Currency
The Company's foreign subsidiaries' balance sheet accounts are translated at the exchange rates in effect at each reporting date and income statement accounts are either translated at the exchange rates on the date of the transaction or at average exchange rates. Foreign currency translation gains and losses are reflected in Stockholders' equity as a component of AOCI. Foreign currency transaction gains (losses) of less than $1 million, $27 million and $(9) million were included in determining Net income (loss) for the years ended December 31, 2018, 2017 and 2016.
## Property and Equipment
Property and equipment are carried at cost less accumulated depreciation. Depreciation is based on the estimated useful lives of the various classes of property and equipment and is determined principally on the straight-line method. Furniture and fixtures are depreciated over seven years. Office equipment is depreciated over five years. The estimated lives for data processing equipment and software generally range from three to five years, but can be as long as ten years. Leasehold improvements are depreciated over the corresponding lease terms not to exceed the underlying asset life.
|
67,884
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https://cdla.io/permissive-1-0/
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[
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] |
overall_image/76d186cba458cc271422b3a47b4ae113f7a048588ecbae1cd2beb752f0283f15.png
|
The following tables present the estimated fair value and gross unrealized losses of fixed maturity and equity securities in a gross unrealized loss position by the length of time in which the securities have continuously been in that position.
<img src='content_image/1030470.jpg'>
<img src='content_image/1030469.jpg'>
(1) As of January 1, 2018, the Company adopted ASU 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities . The change in fair value of equity securities is now recognized through the income statement. See Note A to the Consolidated Financial Statements for additional information.
|
67,885
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https://cdla.io/permissive-1-0/
|
[
"content_image/1054908.jpg",
"content_image/1054909.jpg"
] |
overall_image/15dd07d15edcf469c7ec1326dbd537aa038b87975e11514e093c363585c6e66c.png
|
Based on current facts and circumstances, the Company believes the unrealized losses presented in the December 31, 2018 securities in a gross unrealized loss position table above are not indicative of the ultimate collectibility of the current amortized cost of the securities, but rather are attributable to changes in interest rates, credit spreads and other factors. The Company has no current intent to sell securities with unrealized losses, nor is it more likely than not that it will be required to sell prior to recovery of amortized cost; accordingly, the Company has determined that there are no additional OTTI losses to be recorded as of December 31, 2018.
The following table presents the activity related to the pretax credit loss component reflected in Retained earnings on fixed maturity securities still held as of December 31, 2018, 2017 and 2016 for which a portion of an OTTI loss was recognized in Other comprehensive income (loss).
<img src='content_image/1054908.jpg'>
## Contractual Maturity
The following table presents available-for-sale fixed maturity securities by contractual maturity.
<img src='content_image/1054909.jpg'>
Actual maturities may differ from contractual maturities because certain securities may be called or prepaid. Securities not due at a single date are allocated based on weighted average life.
## Limited Partnerships
The carrying value of limited partnerships as of December 31, 2018 and 2017 was $1,982 million and $2,369 million, which includes net undistributed earnings of $153 million and $539 million. Limited partnerships comprising 60% of the total carrying value are reported on a current basis through December 31, 2018 with no reporting lag, 14% are reported on a one month lag and the remainder are reported on more than a one month lag. The number of limited partnerships held and the strategies employed provide diversification to the limited partnership portfolio and the overall invested asset portfolio.
Limited partnerships comprising 65% and 71% of the carrying value as of December 31, 2018 and 2017 employ hedge fund strategies. Limited partnerships comprising 30% and 25% of the carrying value as of December 31, 2018 and 2017 were invested in private debt and equity. The remainder was primarily invested in real estate strategies. Hedge fund strategies include both long and short positions in fixed income, equity and derivative instruments. These hedge fund strategies may seek to generate gains from mispriced or undervalued securities, price differentials between securities, distressed investments, sector rotation or various arbitrage disciplines. Within hedge fund strategies, approximately 60% were equity related, 18% pursued a multi-strategy approach, 19% were focused on distressed investments and 3% were fixed income related as of December 31, 2018.
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67,886
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https://cdla.io/permissive-1-0/
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[
"content_image/1023143.jpg"
] |
overall_image/8d490e0f11b2b5d6224cfdd7453f2530807f03c8f8a40688c74982bc83b5c2ea.png
|
The deferred tax effects of the significant components of the Company's deferred tax assets and liabilities are presented in the following table.
<img src='content_image/1023143.jpg'>
As of December 31, 2018, the CNA Tax Group had no loss carryforwards or tax credit carryforwards.
Although realization of deferred tax assets is not assured, management believes it is more likely than not that the recognized net deferred tax asset will be realized through recoupment of ordinary and capital taxes paid in prior carryback years and through future earnings, reversal of existing temporary differences and available tax planning strategies. As a result, no valuation allowance was recorded as of December 31, 2018 or 2017.
|
67,887
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https://cdla.io/permissive-1-0/
|
[] |
overall_image/bd9b7a00cc4d23e79fb17035657cba4be93a323720e2bbfa8b5ecdbd7106e15f.png
|
## Segment Development Tables
For the Specialty, Commercial and International segments, the following tables present further detail and commentary on the development reflected in the financial statements for each of the periods presented. Also presented are loss reserve development tables that illustrate the change over time of reserves established for claim and allocated claim adjustment expenses arising from short duration insurance contracts for certain lines of business within each of these segments. Not all lines of business or segments are presented based on their context to the Company's overall loss reserves, calendar year reserve development, or calendar year net earned premiums. Insurance contracts are considered to be short duration contracts when the contracts are not expected to remain in force for an extended period of time.
The Cumulative Net Incurred Claim and Allocated Claim Adjustment Expenses tables, reading across, show the cumulative net incurred claim and allocated claim adjustment expenses relating to each accident year at the end of the stated calendar year. Changes in the cumulative amount across time are the result of the Company's expanded awareness of additional facts and circumstances that pertain to the unsettled claims. The Cumulative Net Paid Claims and Allocated Claim Adjustment Expenses tables, reading across, show the cumulative amount paid for claims in each accident year as of the end of the stated calendar year. The Net Strengthening or (Releases) of Prior Accident Year Reserves tables, reading across, show the net increase or decrease in the cumulative net incurred accident year claim and allocated claim adjustment expenses during each stated calendar year and indicates whether the reserves for that accident year were strengthened or released.
The information in the tables is reported on a net basis after reinsurance and does not include the effects of discounting. The information contained in calendar years 2017 and prior is unaudited. Information contained in the tables pertaining to the Company's International segment has been presented at the year-end 2018 foreign currency exchange rates for all periods presented to remove the effects of foreign currency exchange rate changes between calendar years. The Company has presented development information for the Hardy business prospectively from the date of acquisition and is presented as a separate table within the Company's International segment. To the extent the Company enters into a commutation, the transaction is reported on a prospective basis. To the extent that the Company enters into a disposition, the effects of the disposition are reported on a retrospective basis by removing the balances associated with the disposed of business.
The amounts reported for the cumulative number of reported claims include direct and assumed open and closed claims by accident year at the claimant level. The number excludes claim counts for claims within a policy deductible where the insured is responsible for payment of losses in the deductible layer. Claim count data for certain assumed reinsurance contracts is unavailable.
IBNR includes reserves for incurred but not reported losses and expected development on case reserves. The Company does not establish case reserves for ALAE, therefore ALAE reserves are also included in the estimate of IBNR.
|
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https://cdla.io/permissive-1-0/
|
[
"content_image/1044478.jpg"
] |
overall_image/f85be490a927cdda1e8adb0322e4d10f700fbc4e2ea686af66060549cd82646e.png
|
## Commercial
The following table presents further detail of the development recorded for the Commercial segment.
## Years ended December 31
<img src='content_image/1044478.jpg'>
## 2018
Unfavorable development in general liability was driven by higher than expected claim severity in unsupported umbrella in accident years 2013 through 2016.
Favorable development in workers’ compensation was driven by lower frequency and severity experience and favorable impacts from California reforms.
Favorable development in property and other was driven by lower than expected claim severity in catastrophes in accident year 2017.
## 2017
Favorable development in commercial auto was primarily due to lower than expected severity in accident years 2013 through 2016, as well as a large favorable recovery on a claim in accident year 2012.
Favorable development in general liability was due to lower than expected severity in life sciences.
Favorable development in workers’ compensation was primarily related to decreases in frequency and severity in recent accident years, partially attributable to California reforms impacting medical costs. This was partially offset by unfavorable development related to an adverse arbitration ruling on reinsurance recoverables from older accident years as well as the recognition of loss estimates associated with earned premium from a prior exposure year.
## 2016
Favorable development in commercial auto was primarily due to favorable settlements on claims in accident years 2010 through 2014 and lower than expected severities in accident years 2012 through 2015.
Favorable development in general liability was primarily due to better than expected claim settlements in accident years 2012 through 2014, better than expected severity on umbrella claims in accident years 2010 through 2013, and better than expected severity in medical products liability in accident years 2010 through 2015. This was partially offset by unfavorable development related to an increase in reported claims prior to the closing of the three year window set forth by the Minnesota Child Victims Act in accident years 2006 and prior.
Unfavorable development in workers' compensation was primarily due to higher than expected severity for Defense Base Act contractors that largely resulted from a reduction of expected future recoveries from the US Department of Labor under the War Hazard Act. Further unfavorable development was due to the impact of recent Florida court rulings for accident years 2008 through 2015. These were partially offset by favorable development related to lower than expected frequencies related to our ongoing Middle Market and Small Business results for accident years 2009 through 2014.
Favorable development in property and other was primarily due to better than expected loss frequency in accident years 2013 through 2015. This was partially offset by unfavorable development related to higher than expected severity from a fourth quarter 2015 catastrophe event.
|
67,889
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https://cdla.io/permissive-1-0/
|
[
"content_image/1046193.jpg",
"content_image/1046199.jpg",
"content_image/1046198.jpg",
"content_image/1046197.jpg"
] |
overall_image/afa31dccfd902b0448e16406aa47a11f742bc18898baaca842953e170d433cbd.png
|
## For The Yea r Ended December 31, 2019
## CRAWFORD & COMPANY
## Table of Contents
## FORM 10-K
## PART I
<img src='content_image/1046193.jpg'>
## PART II
<img src='content_image/1046199.jpg'>
## PART III
<img src='content_image/1046198.jpg'>
## PART IV
<img src='content_image/1046197.jpg'>
|
67,890
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https://cdla.io/permissive-1-0/
|
[] |
overall_image/43347afea25615a26b3a429849d2c565f694278d2ba44a244fdc98823b7b1ec7.png
|
## BUSINESS AND OPERATIONS
## A significant portion of our operations are international. These international operations subject us to political, legal, operational, exchange rate and other risks not generally present in U.S. operations, which could materially negatively affect those operations or our business as a whole.
Our international operations subject us to political, legal, operational, exchange rate and other risks that we do not face in our domestic operations. We face, among other risks, the risk of discriminatory regulation; nationalization or expropriation of assets; changes in both domestic and foreign laws regarding taxation, trade and investment abroad; pandemics such as coronavirus; potential loss of proprietary information due to piracy, misappropriation or laws that may be less protective of our intellectual property rights; or price controls and exchange controls or other restrictions that could prevent us from transferring funds from these operations out of the countries in which they were earned or converting local currencies we hold into U.S. dollars or other currencies.
International operations also subject us to numerous additional laws and regulations that are in addition to, or may be different from, those affecting U.S. businesses, such as those related to labor, employment, worker health and safety, antitrust and competition, trade restriction, environmental protection, consumer protection, import/export and anti-corruption, including but not limited to the Foreign Corrupt Practices Act ("FCPA"). Although we have put into place policies and procedures aimed at ensuring legal and regulatory compliance, our employees, subcontractors, and agents could inadvertently or intentionally take actions that violate any of these requirements. Violations of these regulations could impact our ability to conduct business, or subject us to criminal or civil enforcement actions, any of which could have a material adverse effect on our business, financial condition or results of operations.
## We have operations in the United Kingdom ("U.K.") and the European Union that may be impacted by the U.K.'s departure from the EU, known as "Brexit". The uncertainty as to the outcome of Brexit after the transition period expires may negatively impact operations in this region or our business as a whole.
The U.K. and EU insurance markets in which we operate may be impacted by the various potential outcomes of Brexit. There are multiple regulatory, contractual, and supply chain issues that need to be considered, and also the potential impact to transactions and assets denominated in foreign currencies. The majority of our relationships in these countries are within our country of operations, however, to the extent we provide services cross-border, there may be increased risks regarding employee mobility, cross-border payments, data transfer and potential regulatory impacts. Failure to secure a pan-European agreement could lead to various country-by-country approaches being implemented, resulting in a lack of consistency between countries. Changes to these regulations could impact our ability to conduct business in these countries, which could have a material adverse effect on our business, results of operations, and financial condition.
## We currently, and from time to time in the future may, outsource a portion of our internal business functions to third-party providers. Outsourcing these functions has significant risks, and our failure to manage these risks successfully could materially adversely affect our business, results of operations, and financial condition.
We currently, and from time to time in the future may, outsource significant portions of our internal business functions to third-party providers. Third-party providers may not comply on a timely basis with all of our requirements, or may not provide us with an acceptable level of service. In addition, our reliance on third-party providers could have significant negative consequences, including significant disruptions in our operations and significantly increased costs to undertake our operations, either of which could damage our relationships with our customers. As a result of our outsourcing activities, it may also be more difficult for us to recruit and retain qualified employees for our business needs at any time. Our failure to successfully outsource any material portion of our business functions could materially adversely affect our business, results of operations, and financial condition.
|
67,891
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https://cdla.io/permissive-1-0/
|
[
"content_image/1056476.jpg",
"content_image/1056477.jpg",
"content_image/1056478.jpg"
] |
overall_image/92a1cd50288f46d06fea20f3609b4e7f1f4d9e147e9fa884ec5276596cb95a8b.png
|
The Company's reportable segments' total operating earnings reconciled to consolidated income before income taxes for the years ended December 31, 2019, 2018, and 2017 were as follows:
<img src='content_image/1056476.jpg'>
The Company's reportable segments' total assets reconciled to consolidated total assets of the Company at December 31, 2019 and 2018 are presented in the following table:
<img src='content_image/1056477.jpg'>
Revenues and long-lived assets for the U.S., U.K. and Canada are set out below as these countries are material for geographical area disclosure. For the purposes of these geographic area disclosures, long-lived assets consists of the net property and equipment, capitalized software costs, net and operating lease right-of-use, net line items on the Company's Consolidated Balance Sheets and excludes intangible assets, including goodwill.
<img src='content_image/1056478.jpg'>
|
67,892
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https://cdla.io/permissive-1-0/
|
[
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overall_image/a0397385d334d1ca6372c57e13d05a37a2be885816d0d4460df4d884acbb5956.png
|
## CRAWFORD & COMPANY QUARTERLY FINANCIAL DATA (UNAUDITED)
<img src='content_image/1034471.jpg'>
|
67,893
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Management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2019. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013 framework). Based on this assessment, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2019.
The Company's independent registered public accounting firm, Ernst & Young LLP, is appointed by the Audit Committee. Ernst & Young LLP has audited and reported on the consolidated financial statements of Crawford & Company and the Company's internal control over financial reporting, each as contained in this Annual Report on Form 10-K.
## Changes in Internal Control over Financial Reporting
There were no changes in the Registrant's internal control over financial reporting during the quarter ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, the Registrant's internal control over financial reporting.
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## ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as part of this report:
1. Financial Statements
## PART IV
The financial statements listed below and the related report of Ernst & Young LLP are incorporated herein by reference and included in Item 8 of this Annual Report on Form 10-K:
• Consolidated Balance Sheets as of December 31, 2019 and 2018
• Consolidated Statements of Operations for the Years Ended December 31, 2019, 2018, and 2017
• Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2019, 2018, and 2017
• Consolidated Statements of Shareholders' Investment for the Years Ended December 31, 2019, 2018, and 2017
• Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018, and 2017
• Notes to Consolidated Financial Statements
2. Financial Statement Schedule
• Schedule II — Valuation and Qualifying Accounts — Information required by this schedule is included under the caption "Accounts Receivable and Allowance for Doubtful Accounts" in Note 1 and also in Note 7, "Income Taxes" to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K, and is incorporated herein by reference.
Other schedules have been omitted because they are not applicable.
3. Exhibits filed with this report.
## Exhibit No.
## Document
2.1 Membership Interest Purchase Agreement, dated December 6, 2016, by and among Crawford Innovative Ventures, LLC, Robin Smith, Mathew Smith, Kenneth Knoll and Those Additional Sellers Listed on Exhibit A (incorporated by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K filed with the Securities and Exchange Commission on January 5, 2017.
2.2 Membership Interest Purchase Agreement, dated June 15, 2018 by and between Crawford & Company, Crawford & Company (Canada) Inc., Epiq Class Action & Claims Solutions, Inc. and Epiq Systems Canada ULC (incorporated by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K filed with the Securities and Exchange Commission on June 18, 2018.
3.1 Restated Articles of Incorporation of the Registrant (incorporated by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K filed with the Securities and Exchange Commission on May 14, 2007).
3.2 Restated By-laws of the Registrant, as amended (incorporated by reference to Exhibit 3.1 of the Registrant's Current Report on Form 8-K filed with the Securities and Exchange Commission on February 12, 2016).
10.1* Crawford & Company Non-Employee Director Stock Plan (as amended effective May 11, 2016).
10.2* Crawford & Company Supplemental Executive Retirement Plan as Amended and Restated December 20, 2007, effective as of January 1, 2007 (incorporated by reference to Exhibit 10.4 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2007).
10.3* Crawford & Company Deferred Compensation Plan, as amended and restated as of January 1, 2003 (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2003).
10.4* Crawford & Company amended and restated Executive Stock Bonus Plan (incorporated by reference to Exhibit 99.1 to the Registrant's Registration statement on Form S-8 (File No. 333-199915) filed with the Securities and Exchange Commission on November 6, 2014).
10.5* Form of Restricted Share Unit Award under the Registrant's Executive Stock Bonus Plan (incorporated by reference to Exhibit 10.11 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2007).
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## COMPETITION AND EMPLOYEES
## We operate in highly competitive markets and face intense competition from both established entities and new entrants into those markets. Potential consolidation in our industry can also create stronger competition. Our failure to compete effectively may adversely affect us.
Our ability to retain clients and maintain and increase case referrals is also dependent in part on our ability to continue to provide high-quality, competitively priced services and effective sales efforts.
The global claims management services market is highly competitive and comprised of a large number of companies that vary in size and that offer a varied scope of services. The demand from insurance companies and self-insured entities for services provided by independent claims service firms like us is largely dependent on industry-wide claims volumes, which are affected by, among other things, the insurance underwriting cycle, weather-related events, general economic activity, overall employment levels, and workplace injury rates. We are also impacted by decisions insurance companies and self-insured entities make with respect to the level of claims outsourced to independent claim service firms as opposed to those handled by their own in-house claims adjusters.
We also face competition from potential new entrants into the global claims management services market, in addition to traditional competitors. Potential consolidation in our industry can also create stronger competition. Our inability to react to such competition or improved technology could negatively impact our volume of case referrals and results of operations.
## We may not be able to recruit, train, and retain qualified personnel, including retaining a sufficient number of qualified and experienced on-call claims adjusters, to respond to catastrophic events that may, singularly or in combination, significantly increase our clients' needs for adjusters.
Our catastrophe related work and revenues can fluctuate dramatically based on the frequency and severity of natural and man-made disasters. When such events happen, our clients usually require a sudden and substantial increase in the need for catastrophic claims services, which can strain our capacity. Our internal resources are sometimes not sufficient to meet these sudden and substantial increases in demand. When these situations occur, we must retain outside adjusters (temporary employees and contractors) to increase our capacity. There can be no assurance that we will be able to retain such outside adjusters with the requisite qualifications, at the times needed or on terms that we believe are economically reasonable. Insurance companies and other loss adjusting firms also aggressively compete for the same pool of independent adjusters, who often command high prices for their services at such times of peak demand. Such competition could reduce availability, increase our costs and reduce our revenues. Our failure to timely, efficiently, and competently provide these services to our cl ients could result in reduced revenues, loss of customer goodwill and a materially negative impact on our results of operations.
## We compete for nurses and other case management professionals in the healthcare industry, which may increase our labor costs and reduce profitability.
Our Crawford TPA Solutions business competes with the general healthcare industry in recruiting qualified nurses, other case management professionals and other talent. In some markets, the scarcity of nurses and other medical support personnel has become a significant operating issue to healthcare providers. Such competition could reduce availability, increase our costs and reduce our revenues. This shortage may require us to increase wages and benefits to recruit and retain qualified nurses and other healthcare professionals. Our failure to recruit and retain qualified management, nurses, and other healthcare professionals, or to control labor costs could result in reduced revenues, loss of customer goodwill and a materially negative impact on our results of operations.
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## Table of Contents
(1) This is a segment financial measure calculated in accordance with ASC Topic 280, "Segment Reporting," and representing segment earnings before certain unallocated corporate and shared costs and credits, net corporate interest expense, stock option expense, amortization of customer-relationship intangible assets, goodwill and intangible asset impairment charges, restructuring and special charges, loss on disposition of business line, arbitration and claim settlements, income taxes, and net income or loss attributable to noncontrolling interests and redeemable noncontrolling interests.
(2) The Company computes earnings (loss) per share of CRD-A and CRD-B using the two-class method, which allocates the undistributed earnings (loss) for each period to each class on a proportionate basis. The Company's Board of Directors has the right, but not the obligation, to declare higher dividends on CRD-A than on CRD-B, subject to certain limitations. In periods when the dividend is the same for CRD-A and CRD-B or when no dividends are declared or paid to either class, the two-class method generally will yield the same earnings (loss) per share for CRD-A and CRD-B.
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## ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") is intended to help the reader understand Crawford & Company, our operations, and our business environment. This MD&A is provided as a supplement to — and should be read in conjunction with — our audited consolidated financial statements and the accompanying notes thereto contained in Item 8, "Financial Statements and Supplementary Data," of this Annual Report on Form 10-K. As described in Note 1, "Significant Accounting and Reporting Policies," of those accompanying audited consolidated financial statements, financial results from our operations outside of the U.S., Canada, the Caribbean, and certain subsidiaries in the Philippines, are reported and consolidated on a two-month delayed basis in accordance with the provisions of ASC 810, "Consolidation," in order to provide sufficient time for accumulation of their results. Accordingly, the Company's Dece mber 31, 2019, 2018 , and 2017 consolidated financial statements include the financial position of such operations as of October 31, 2019 and 2018 , respectively, and the results of their operations and cash flows for the fiscal periods ended October 31, 201 9 , 2018 and 2017 , respectively.
## Business Overview
Based in Atlanta, Georgia, Crawford & Company (www.crawco.com) is th e world's largest publicly listed independent provider of claims management and outsourcing solutions to carriers, brokers and corporates with an expansive global network serving clients in mor e tha n 70 countries. Shares of the Company's two classes of common stock are traded on the NYSE under the symbols CRD-A and CRD-B, respectively. The Company's two classes of stock are substantially identical, except with respect to voting rights and the Company's ability to pay greater cash dividends on the non-voting Class A Common Stock than on the voting Class B Common Stock, subject to certain limitations. In addition, with respect to mergers or similar transactions, holders of Class A Common Stock must receive the same type and amount of consideration as holders of Class B Common Stock, unless different consideration is approved by the holders of 75% of the Class A Common Stock, voting as a class.
As discussed in more detail in subsequent sections of this MD&A, we have three operating segments: Crawford Claims Solutions, Crawford TPA Solutions, and Crawford Specialty Solutions. Our three operating segments represent components of the Company for which separate financial information is available, and which is evaluated regularly by our chief operating decision maker ("CODM") in deciding how to allocate resources and in assessing operating performance. Crawford Claims Solutions serves the global property and casualty insurance company markets. Crawford TPA Solutions serves the global casualty, disability and self-insurance marketplace worldwide. Crawford Specialty Solutions serves the global property and casualty insurance company markets.
Insurance companies rely on us for certain services such as field investigation and the evaluation of property and casualty insurance claims. Self-insured entities typically rely on us for a broader range of services. In addition to field investigation and claims evaluation, we may also provide initial loss reporting services for their claimants, loss mitigation services such as medical bill review, medical case management and vocational rehabilitation, risk management information services, and trust fund administration to pay their claims. Our Contractor Connection service line in our Crawford Specialty Solutions segment provides a managed contractor network to insurance carriers and consumer markets.
The global claims management services market is highly competitive and comprised of a large number of companies that vary in size and that offer a varied scope of services. The demand from insurance companies and self-insured entities for services provided by independent claims service firms like us is largely dependent on industry-wide claims volumes, which are affected by, among other things, the insurance underwriting cycle, weather-related events, general economic activity, overall employment levels and workplace injury rates. Demand is also impacted by decisions insurance companies and self-insured entities make with respect to the level of claims outsourced to independent claim service firms as opposed to those handled by their own in-house claims adjusters. In addition, our ability to retain clients and maintain or increase case referrals is also dependent in part on our ability to continue to provide high-quality, competitively priced services and effective sales efforts.
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We typically earn our revenues on an individual fee-per-claim basis for claims management services we provide to insurance companies and self-insured entities. Accordingly, the volume of claim referrals to us is a key driver of our revenues. Generally, fees are earned over time on cases as services are provided, which generally occurs in the period the case is assigned to us, although sometimes a portion or substantially all of the revenues generated by a specific case assignment will be earned in subsequent periods. We cannot predict the future trend of case volumes for a number of reasons, including the frequency and severity of weather-related cases and the occurrence of natural and man-made disasters, which are a significant source of cases for us and are not subject to accurate forecasting.
We recognized arbitration and claim settlement charges in 2019 of $12.6 million related to an arbitration panel awarding three of four former executives of our former Garden City Group business unit additional payments associated with their departure from the Garden City Group on December 31, 2015, and a claim settlement with the fourth former executive. There are no other potential claimants related to this matter. This pretax expense is presented in the Consolidated Statements of Operations as a separate charge "Arbitration and claim settlements."
We recognized a non-cash goodwill impairment charge in 2019 totaling $17.5 million related to our Crawford Claims Solutions segment, due to lower forecasts in that reporting unit. This charge was partially offset by a $2.2 million reduction in income tax expense and $2.2 million credit in noncontrolling interest expense. There were no goodwill impairment charges in 2018. See the "Critical Accounting Policies" in Item 7 and Note 4, "Goodwill and Intangible Assets" of our accompanying audited consolidated financial statements included in Item 8 of this Annual Report on Form 10-K for further discussion about goodwill impairment charges.
In 2019, we recognized a $2.0 million non-recurring deferred tax asset valuation allowance related to certain state net operating loss carryforwards, foreign tax credits and capital losses.
In 2018, we recognized an impairment of $1.1 million related to an indefinite-lived trade name due to a combination of achieving less than forecasted revenue compared to previous modeled results and further reduced forecasted revenue associated with the trade name.
On June 15, 2018, we completed the sale of our Garden City Group business (the “GCG Business”) to EPIQ Class Action & Claims Solutions, Inc. ("EPIQ") for cash proceeds of $42.6 million. At the time of the disposal, the GCG Business included total assets of $70.6 million and total liabilities of $10.1 million. The total asset balance was primarily comprised of accounts receivable, unbilled revenues and capitalized software costs. After including transaction and other costs related to the sale, we recognized a pretax loss on the disposal of $20.3 million. The loss on disposal is presented in the Consolidated Statements of Operations as a separate charge "Loss on disposition of business line."
On January 4, 2017, we acquired 85% of the outstanding membership interests of WeGoLook$^{®}$, LLC, an Oklahoma limited liability company, and certain non-compete agreements, for consideration of $36.1 million on a debt free valuation basis. WeGoLook provides a variety of on-demand inspection, verification, and other field services for businesses and consumers through a mobile platform of independent contractors.
On December 22, 2017, the Tax Cuts and Jobs Act (the “Tax Act”) was enacted. The Tax Act significantly changed U.S. Federal income tax law. The changes included but were not limited to: a federal corporate rate reduction from 35% to 21%, limitations on the deductibility of interest expense and executive compensation, creation of a new minimum tax on global intangible low taxed income (“GILTI”), and a one-time U.S. tax liability on those earnings which have not previously been repatriated to the U.S. (the “Transition Tax”) as a result of the transition of U.S. international taxation from a worldwide tax system to a modified territorial tax system. In connection with our initial analysis of the impact of the Tax Act, we recorded a provisional estimate in accordance with Staff Accounting Bulletin No. 118 (“SAB 118”) of net tax expense of $3.8 million in the period ended December 31, 2017. This expense consisted of provisional estimates of $7.6 million net expense for the Transition Tax, which we estimated would be fully offset by foreign tax credit carryforwards, and $3.8 million net benefit for remeasurement of our domestic deferred tax balances for the corporate rate reduction. In the period ended December 31, 2018, we completed accounting for the Tax Act in accordance with SAB 118. As a result, we recorded additional income tax expense of $3.6 million. This expense consisted of substantially all of the $7.0 million valuation allowance established against foreign tax credits and $0.1 million for the revaluation of deferred taxes, net of $3.5 million of Transition Tax release of uncertain tax positions and adjustments. We completed the accounting for the Tax Act within the one year measurement period, as allowed under SAB 118.
See Note 7, "Income Taxes” of our accompanying audited consolidated financial statements included in Item 8 of this Annual Report on Form 10-K for further discussion about income taxes.
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Although operating earnings is the primary financial performance measure used by our senior management and CODM to evaluate the financial performance of our operating segments and make resource allocation and certain compensation decisions, we believe that a non-GAAP discussion and analysis of segment gross profit is also helpful in understanding the results of our segment operations excluding indirect centralized administrative support costs. Our discussion and analysis of segment gross profit includes the revenues and direct expenses of each segment. Segment gross profit is defined as revenues, less direct costs, which exclude indirect centralized administrative support costs allocated to the business.
In the Crawford Claims Solutions segment, operating earnings declined primarily due to the reduction in revenues and an increase in centralized indirect administrative support costs during 2019. Excluding indirect support costs, gross profit decreased from $78.3 million, or 21.7% of revenues before reimbursements in 2018, to $76.7 million, or 22.6% of revenues before reimbursements in 2019.
In the Crawford TPA Solutions segment, operating earnings declined primarily due to a reduction in revenues and a gross profit decline during 2019. Excluding indirect support costs, gross profit decreased from $109.2 million, or 26.9% of revenues before reimbursements in 2018, to $99.7 million, or 25.3%, as direct costs grew at a higher rate than revenues.
In the Crawford Specialty Solutions segment, operating earnings declined as a result of increased compensation expense compared to 2018. Excluding indirect support costs, gross profit decreased from $105.5 million, or 34.6% of revenues before reimbursements in 2018, to $95.4 million, or 35.1%, due primarily to the Garden City Group business which contributed $6.2 million gross profit in the 2018 period.
Cost of services provided, before reimbursements, decreased $45.0 million, or 6.0% for 2019 compared with 2018. The decrease was primarily due to the disposition of the Garden City Group, which had $22.3 million of expenses in 2018, lower expenses in our Crawford Claims Solutions segment to support the decrease the weather related activity, and changes in foreign exchange rates.
Selling, general and administrative ("SG&A") expenses were $15.3 million lower, a decrease of 6.3%, in 2019 compared to 2018. The decrease in 2019 was due to a decrease in non-employee labor, professional fees, and other administrative expenses, and the Garden City Group disposition, which had $11.6 million of expenses in 2018.
The Company recognized arbitration and claim settlement charges in 2019 of $12.6 million related to an arbitration panel awarding three of four former executives of our former Garden City Group business unit additional payments associated with their departure from the Garden City Group on December 31, 2015, and a claim settlement with the fourth former executive.
The Company incurred a non-cash goodwill impairment charge in 2019 totaling $17.5 million. This charge was partially offset by a $2.2 million reduction in income tax expense and $2.2 million credit in noncontrolling interest expense. There were no goodwill impairment charges in 2018, although we recognized a $1.1 million impairment to an indefinite-lived trade name intangible asset.
During 2019, the Company realigned certain operations within Canada from the Crawford Claims Solutions segment to the Crawford Specialty Solutions segment to be consistent with current operating segment responsibilities. Previously reported amounts have been reclassified to reflect these changes. No other changes in operating responsibilities occurred. These transfers are not material to the Company's financial statements.
## Segment Operating Earnings
We believe that a discussion and analysis of the segment operating earnings of our three operating segments is helpful in understanding the results of our operations. Operating earnings is our segment measure of profitability presented in conformity with the Financial Accounting Standards Board's ("FASB") Accounting Standards Codification ("ASC") Topic 280 "Segment Reporting." Operating earnings is the primary financial performance measure used by our senior management and CODM to evaluate the financial performance of our operating segments and make resource allocation and certain compensation decisions.
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We believe operating earnings is a measure that is useful to others in that it allows them to evaluate segment operating performance using the same criteria used by our senior management and CODM. Segment operating earnings represent segment earnings, including the direct and indirect costs of certain administrative functions required to operate our business, but excludes unallocated corporate and shared costs and credits, net corporate interest expense, stock option expense, amortization of customer-relationship intangible assets, goodwill and intangible asset impairment charges, restructuring and special charges, loss on disposition of business line, arbitration and claim settlements, income taxes, and net income or loss attributable to noncontrolling interests and redeemable noncontrolling interests.
Administrative functions such as finance, human resources, information technology, quality and compliance, exist in both a centralized shared- service arrangement and within certain operations. Each of these functions are managed by centralized management and we allocate the costs of those services to the segments as indirect costs based on usage.
Gross profit is defined as segment revenues, less segment direct costs, which exclude centralized indirect administrative support costs allocated to the business.
Income taxes, net corporate interest expense, stock option expense, and amortization of customer-relationship intangible assets are recurring components of our net income, but they are not considered part of our segment operating earnings because they are managed on a corporate-wide basis. Income taxes are calculated for the Company on a consolidated basis based on statutory rates in effect in the various jurisdictions in which we provide services, and vary significantly by jurisdiction. Net corporate interest expense results from capital structure decisions made by senior management and the Board of Directors, affecting the Company as a whole. Stock option expense represents the non-cash costs generally related to stock options and employee stock purchase plan expenses which are not allocated to our operating segments. Amortization expense is a non-cash expense for finite-lived customer-relationship and trade name intangible assets acquired in business combinations. None of these costs relate directly to the performance of our services or operating activities and, therefore, are excluded from segment operating earnings in order to better assess the results of each segment's operating activities on a consistent basis.
Unallocated corporate and shared costs and credits include expenses and credits related to our chief executive officer and Board of Directors, certain provisions for bad debt allowances or subsequent recoveries such as those related to bankrupt clients, defined benefit pension costs or credits for our frozen U.S. pension plan, certain unallocated professional fees, and certain self-insurance costs and recoveries that are not allocated to our individual operating segments.
Restructuring and special charges, as well as loss on disposition of business line, goodwill impairment charges and impairment of intangible assets, and arbitration and claim settlements arise from time to time from events (such as internal restructurings, losses on subleases, establishment of new operations, and asset impairments) that are not allocated to any particular segment since they historically have not regularly impacted our performance and are not expected to impact our future performance on a regular basis.
Additional discussion and analysis of our income taxes, net corporate interest expense, stock option expense, amortization of customer- relationship intangible assets, unallocated corporate and shared costs, goodwill impairment charges and impairment of intangible assets, restructuring and special charges, arbitration and claim settlements, and loss on disposition of business line follows the discussion and analysis of the results of operations of our three operating segments.
## Segment Revenues
In the normal course of business, our operating segments incur certain out-of-pocket expenses that are thereafter reimbursed by our clients. Under GAAP, these out-of-pocket expenses and associated reimbursements are required to be included when reporting expenses and revenues, respectively, in our consolidated results of operations as the Company is considered the principal in these transactions. In the discussion and analysis of results of operations which follows, we do not include a gross up of expenses and revenues for these pass-through reimbursed expenses. The amounts of reimbursed expenses and related revenues offset each other in our results of operations with no impact to our net income or operating earnings. A reconciliation of revenues before reimbursements to consolidated revenues determined in accordance with GAAP is self- evident from the face of the accompanying statements of operations. Unless noted in the following discussion and analysis, revenue amounts exclude reimbursements for out-of-pocket expenses.
Our segment results are impacted by changes in foreign exchange rates. We believe that a non-GAAP discussion and analysis of segment revenues before reimbursements by major region, based on actual exchange rates and using a constant exchange rate, is helpful in understanding the results of our segment operations. Revenues in our Crawford Specialty Solutions segment are also impacted by the disposition of the Garden City Group service line as of June 15, 2018.
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The table below, read together with the reconciliation on the previous page, represents gross profit for our segments reconciled to net income attributable to shareholders of Crawford & Company.
<img src='content_image/1040030.jpg'>
* See table on the previous page for a reconciliation of segment operating earnings to Net income attributable to shareholders of Crawford & Company.
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## YEAR ENDED DECEMBER 31, 2019 COMPARED WITH YEAR ENDED DECEMBER 31, 2018
## CRAWFORD CLAIMS SOLUTIONS SEGMENT
## Operating Earnings
Our Crawford Claims Solutions segment reported operating earnings of $7.6 million, or 2.2% of revenues before reimbursements in 2019, as compared to $11.3 million, or 3.1% of revenues before reimbursements in 2018. Operating earnings decreased from 2018 to 2019 primarily due to a decrease in weather related claim activity and associated revenues in the U.S. and Canada, and lower earnings in Canada and Europe. There was also an increase in centralized administrative support costs to expand technology and sales efforts in 2019.
Excluding centralized indirect support costs, gross profit decreased from $78.3 million, or 21.7% of revenues before reimbursements in 2018, to $76.7 million, or 22.6% of revenues before reimbursements in 2019, due primarily to lower earnings in Canada and Europe, partially offset by improved performance in the U.S. and lower compensation costs in 2019 compared to 2018.
## Revenues before Reimbursements
Crawford Claims Solutions revenues are primarily derived from the global property and casualty insurance company markets in the U.S., U.K., Canada, Australia, Europe and Rest of World. Cr awford Claims Solutions revenues before reimbursements by major region, based on actual exchange rates and using a constant exchange rate were as follows:
<img src='content_image/1020847.jpg'>
Revenues before reimbursements from our Crawford Claims Solutions segment totaled $339.8 million in 2019 compared with $361.1 million in 2018. This decrease was primarily due to a decrease in weather-related activity in the U.S. as the 2018 period included the runoff of 2017 hurricane claims activity, which negatively impacted revenues by $13.4 million, or 3.7% of Crawford Claims Solutions segment revenues. Changes in foreign exchange rates resulted in a decrease of our Crawford Claims Solutions segment revenues by approximately 3.0%, or $10.7 million for 2019. Absent foreign exchange rate fluctuations, Crawford Claims Solutions segment revenues would have been $350.5 million for 2019. Revenues were negatively impacted by a decrease in unit volumes, measured principally by cases received, which decreased revenues 9.0% in 2019 compared with 2018. Changes in product mix and in the rates charged for those services accounted for a 9.8% revenue increase for 2019 compared with the 2018 period due to a decrease in high-frequency, low-complexity cases in the U.S.
There was a decrease in revenues in the U.S. for 2019 due to the decrease in weather related activity referenced above. Based on constant foreign exchange rates, there was an increase in revenues in the U.K. for 2019 compared with 2018 due to an increase in new clients and expanding new services. Revenues in Canada decreased in 2019 compared with the 2018 period due to a reduction in weather related activity resulting from the Ontario windstorms in 2018. There was a revenue increase in Australia due to an increase in weather related case activity in 2019. There was a slight revenue increase in Europe. The decrease in revenues in Rest of World for 2019 compared with 2018 was due to a reduction in weather related case activity in Asia and Latin America.
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## CRAWFORD TPA SOLUTIONS SEGMENT
## Operating Earnings
Our Crawford TPA Solutions s egment, which operates under the Broadspire brand globally, reported operating earnings of $27 .2 million , or 6.9% of revenues before reimbursements in 2 019 , as compared to $36.9 million, or 9.1% of revenues before reimbursements in 2 018 . The decrease in operating earnings for the 2019 period resulted from lower revenues, which were not fully offset by lower direct expenses.
Excluding centralized indirect support costs, gross profit decreased from $109.2 million, or 26.9% of revenues before reimbursements in 2018, to $99.7 million, or 25.3% of revenues before reimbursements in 2019, as the decrease in direct costs did not offset the reduction in revenues.
## Revenues before Reimbursements
Crawford TPA Solutions revenues are from the global casualty and disability insurance and self-insured markets in the U.S., U.K., Canada, and Europe and Rest of World. Revenues before reimbursements by major region, based on actual exchange rates and using a constant exchange rate were as follows:
<img src='content_image/1049429.jpg'>
Revenues before reimbursements from our Crawford TPA Solutions totaled $393.9 million in 2019, compared to $405.3 million in 2018. Changes in foreign exchange rates decreased our Crawford TPA Solutions segment revenues by $3.7 million, or approximately 0.9%, for 2019. Absent foreign exchange rate fluctuations, Crawford TPA Solutions segment revenues would have been $397.6 million in 2019. Revenues were negatively impacted by a decrease in unit volumes, measured principally by cases received, of 2.6% in 2019 compared with 2018. Changes in product mix and in the rates charged for those services accounted for a 0.7% revenue increase for 2019 compared with the 2018 period.
The decrease in revenues in the U.S. for 2019 as compared with the 2018 period was primarily due to a delayed ramp up of new Claims Management and Medical Management clients and isolated client losses, partially offset by an increase in high-frequency, low-complexity disability cases. Based on constant foreign exchange rates, the decrease in revenues in the U.K. for 2019 was due to client case volume decreases and a change in the mix of services provided. Revenues in Canada decreased due to a change in the mix of services provided and a reduction in case volumes. Revenues increased in Europe and Rest of World due to growth from both new and existing clients.
## Reimbursed Expenses Included in Total Revenues
Reimbursements for out-of-pocket expenses incurred in our Crawford TPA Solutions segment which are included in total Company revenues increased to $11.6 million in 2019 from $10.5 million in 2018. This was due an increased use of third parties in Europe in the 2019 period.
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At December 31, 2019, the Company was in compliance with the financial covenants under the Credit Facility. Our leverage ratio was 1.53 and 1.48 as of December 31, 2019 and December 31, 2018, respectively, and our fixed charge coverage ratio was 1.46 and 2. 50 as of December 31, 2019 and December 31, 2018, respectively. If the Company does not meet the covenant requirements in the future, it would be in default under the Credit Facility. Upon the occurrence of an event of default, the lenders may terminate the loan commitments, accelerate all loans and exercise any of their rights under the Credit Facility and ancillary documents.
We are not aware of any additional restrictions placed on us, or being considered to be placed on us, related to our ability to access capital, such as borrowings under the Credit Facility. We do not rely on repurchase agreements or the commercial paper market to meet our short-term or long-term funding needs. For additional information on the key covenants contained in our Credit Facility, see "Other Matters Concerning Liquidity and Capital Resources" below.
We continue the ongoing monitoring of our customers' ability to pay us for the services that we provide to them. Based on historical results, we currently believe there is a low likelihood that write-offs of our existing accounts receivable will have a material impact on our financial results. However, if one or more of our key customers files bankruptcy or otherwise becomes unable to make required payments to us, or if overall economic conditions deteriorate, we may need to make material provisions in the future to increase our allowance for accounts receivable.
The operations of each of our reporting segments expose us to a number of risks, including foreign currency exchange rate changes that can impact translations of foreign-denominated assets and liabilities into U.S. dollars and future earnings and cash flows from transactions denominated in different currencies, as well as the risk of changes in tax rates or tariffs on earnings or services provided outside the U.S. Changes in the relative values of non-U.S. currencies to the U.S. dollar affect our financial results. Incr eases in the value of the U.S. dollar compared with the other functional currencies in certain of the locations in which we do business negatively impacted our revenues and operating earnings in 2019 and 2017, but a weaker U.S. dollar positively impacted revenues and operating earnings in 2018. We can not predict the impact that foreign currency exchange rates may have on our future revenues or operating earnings.
At December 31, 2019, our working capital balance (cu rrent assets less current liabilities) was approximately $78.9 million, compared with $95.5 million at December 31, 2018. The decrease in working capital was primarily due to the incremental operating lease liability recorded as part of the implementation of ASC 842. For further discussion of this guidance, refer to Note 1, "Significant Accounting and Reporting Policies" of the audited consolidated financial statements included in Item 8 of this Annual Report on Form 10-K. Cash and cash equivalents at the end of 2019 totaled $51.8 million, compared with $53.1 million at the end of 2018.
Cash and cash equivalents as of December 31, 2019 consisted of $16.2 million held in the U.S. and $35.6 million held in our foreign subsidiaries. All of the cash and cash equivalents held by our foreign subsidiaries is available for general corporate purposes. The Company generally does not provide for additional U.S. and foreign income taxes on undistributed earnings of foreign subsidiaries because they are considered to be indefinitely reinvested. The Company's current expectation is that such earnings will be reinvested by the subsidiaries or will be repatriated only when it would be tax effective or otherwise strategically beneficial to the Company, such as if a very unusual event or project generated profits significantly in excess of ongoing business reinvestment needs. If such an event occurs, we would analyze the potential tax impact or our anticipated investment needs in that region and provide for taxes for earnings that are not expected to be permanently reinvested. Other historical earnings and future foreign earnings necessary for business reinvestment are expected to remain permanently reinvested and will be used to provide working capital for these operations, fund defined benefit pension plan obligations, repay non-U.S. debt, fund capital improvements, and fund future acquisitions. We currently believe that funds expected to be generated from our U.S. operations, along with potential borrowing capabilities in the U.S., will be sufficient to fund our U.S. operations and other obligations, including our funding obligations under our U.S. defined benefit pension plan, for the foreseeable future and, therefore, except in limited circumstances such as those described above, do not foresee a need to repatriate cash held by our foreign subsidiaries in a taxable transaction to fund our U.S. operations.
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## Other Matters Concerning Liquidity and Capital Resources
Our short-term debt obligations typically peak during the first quarter of each year due to the payment of incentive compensation awards, contributions to retirement plans, and certain other recurring payments, and generally decline during the balance of the year. Our maximum month-end short-term debt obligations were $36.6 million and $36.1 million in 2019 and 2018, respectively. Our average month-end short-term debt obligations were $30.8 million and $25.9 million in 2019 and 2018, respectively. The outstanding balance of our short-term borrowings, excluding outstanding but undrawn letters of credit under our Credit Facility, was $28.5 million and $23.2 million at December 31, 2019 and 2018, respectively. The balance in short-term borrowings at December 31, 2019 represents amounts under our revolving Credit Facility that we expect, but are not required, to repay in the next twelve months. We have historically used the proceeds from our long-term borrowings to finance, among other things, business acquisitions.
Based on our financial plans, we expect to be able to remain in compliance with all required covenants throughout 2020. Our compliance with the senior secured leverage ratio and fixed charge coverage ratio is particularly sensitive to changes in our EBITDA, and if our financial plans for 2020 or other future periods do not meet our current projections, we could fail to remain in compliance with these financial covenants in our Credit Facility.
Our compliance with the senior secured leverage ratio covenant is also sensitive to changes in our level of consolidated total funded debt, as defined in our Credit Facility. In addition to short- and long-term borrowings, capital leases, and bank overdrafts, among other things, consolidated total funded debt includes letters of credit, the need for which can fluctuate based on our business requirements. An increase in borrowings under our Credit Facility could negatively impact our leverage ratio, unless those increased borrowings are offset by a corresponding increase in our EBITDA. In addition, a reduction in EBITDA in the future could limit our ability to utilize available credit under the Credit Facility, which could negatively impact our ability to fund our current operations or make needed capital investments.
Our compliance with the fixed charge coverage ratio covenant, which measures our ability to pay certain recurring expenses such as interest and lease payments, is also sensitive to the level of capital expenditures and restricted payments, as defined in our Credit Facility. A decrease in EBITDA could negatively impact our fixed charge coverage ratio, as could increases in our capital expenditures, interest expense, tax expense or restricted payments. If we do not manage those items carefully, we could be in default under the Credit Agreement, which would negatively impact our ability to fund our current operations or make needed capital investments.
We believe our current financial resources, together with funds generated from operations and existing and potential borrowing capabilities, will be sufficient to maintain our current operations for the next 12 months.
## Contractual Obligations
As of December 31, 2019, the impact that our contractual obligations, including estimated interest payments, are expected to have on our liquidity and cash flow in future periods is as follows:
(Note references in the following table refer to the note in the accompanying audited consolidated financial statements in Item 8 of this Annual Report on Form 10-K).
<img src='content_image/1055262.jpg'>
$^{(1)}$ Assumes principal amounts are repaid at maturity and not refinanced.
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Approximately $8.5 million of operating lease obligations included in the table above are expected to be funded by sublessors under existing sublease agreements. See Note 6, "Lease Commitments" to the audited consolidated financial statements included in Item 8 of this Annual Report on Form 10-K.
Borrowings under our Credit Facility bear interest at a variable rate, based on LIBOR or a Base Rate, in either case plus an applicable margin. The Credit Facility defines LIBOR to encompass accepted alternative reference rates for certain currencies where a LIBOR rate is no longer quoted. Long-term debt refers to the required principal repayment at maturity of the Credit Facility, and may differ significantly from estimates, due to, among other things, actual amounts outstanding at maturity or any refinancings prior to such date. Interest amounts are based on projected borrowings under our Credit Facility and interest rates in effect on December 31, 2019, and the actual interest payments may differ significantly from estimates due to, among other things, changes in outstanding borrowings and prevailing interest rates in the future.
At December 31, 2019, we had approximately $5.3 million of unrecognized income tax benefits related to uncertain tax positions. We cannot reasonably estimate when all of these unrecognized income tax benefits may be settled. We expect $1.2 million of reductions to unrecognized income tax benefits within the next 12 months as a result of projected resolutions of income tax uncertainties.
Gross deferred income tax liabilities as of December 31, 2019 were approximately $60.4 million. This amount is not included in the contractual obligations table because we believe this presentation would not be meaningful. Deferred income tax liabilities are calculated based on temporary differences between the tax basis of assets and liabilities and their respective book basis, which will result in taxable amounts in future years when the liabilities are settled at their reported financial statement amounts. The results of these calculations do not have a direct connection with the amount of cash taxes to be paid in any future periods. As a result, we believe scheduling deferred income tax liabilities as payments due by period could be misleading, because this scheduling would not relate to liquidity needs.
## Defined Benefit Pension Funding and Cost
We sponsor a qualified defined benefit pension plan in the U.S., (the "U.S. Qualified Plan") three defined benefit plans in the U.K. (the "U.K. Plans"), and defined benefit pension plans in the Netherlands, Norway, Germany, and the Philippines (the "other international plans"). Future cash funding of our defined benefit pension plans will depend largely on future investment performance, interest rates, changes to mortality tables, and regulatory requirements. Effective December 31, 2002, we froze our U.S. Qualified Plan. The aggregate deficit in the funded status of the U.S. Plan and other international plans totaled $65.9 million and $74.3 million at the end of 2019 and 2018, respectively. The 2019 decrease in the unfunded deficit of our defined benefit pension plans primarily resulted from actuarial gains in the year. We made no contributions in 2019 to our U.S. Qualified Plan and $0.7 million to our U.K. Plans. In 2018, we made contributions of $19.0 million and $5.0 million to our U.S. Qualified Plan and U.K. Plans, respectively. The U.K. Plans were in a funded status totaling $35.0 million and $32.7 million at the end of 2019 and 2018, respectively, with the fair value of plan assets exceeding the projected benefit obligation. There was a $2.3 million decrease during 2019 in the net prepaid pension balances of the U.K. defined benefit plans.
Our frozen U.S. Qualified Plan was underfunded by $63.5 million at December 31, 2019 based on an accumulated benefit obligation of $440.5 million. Crawford expects to make discretionary contributions of $9.0 million per annum to the U.S. Qualified Plan for the next five years to improve the funded status of the plan and minimize future required contributions. We estimate that we will make the following annual minimum contributions over the next five years to our frozen U.S. Qualified Plan.
<img src='content_image/1041945.jpg'>
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We review the expected long-term rate of return on an annual basis and revise it as appropriate. To support our conclusions, we periodically commission asset/liability studies performed by third-party professional investment advisors and actuaries to assist us in our reviews. These studies project our estimated future pension payments and evaluate the efficiency of the allocation of our pension plan assets into various investment categories. These studies also generate probability-adjusted expected future returns on those assets. As a result of the transition to a liability- driven investment strategy described previously, the expected long-term rates of return on plan assets assumption used to determine 2020 net periodic pension cost are estimated to be 5.50% and 2.54% for the U.S. and U.K. plans, respectively.
We review our employee demographic assumptions annually and update the assumptions as necessary. During 2019, we revised the mortality assumptions for the U.S. plans to incorporate the new mortality tables issued by the Society of Actuaries, adjusted to reflect Company-specific experience and future expectations. This resulted in a $3.6 million decrease in the projected benefit obligation for the U.S. plans.
Pension expense is also affected by the accounting policy used to determine the value of plan assets at the measurement date. We apply our expected return on plan assets using fair market value as of the annual measurement date. The fair market value method results in greater volatility to our pension expense than the calculated value method. The amounts recognized in the balance sheet reflect a snapshot of the state of our long-term pension liabilities at the plan measurement date and the effect of mark-to-market accounting on plan assets. At December 31, 2019, we recorded an increase to equity through other comprehensive income ("OCI") of $1.0 million (net of tax at the applicable jurisdictional rate) to reflect unrealized actuarial gains during 2019. At December 31, 2018, we recorded a decrease to equity through OCI of $18.0 million (net of tax at the applicable jurisdictional rate) to reflect unrealized actuarial losses during 2018. Those changes are subject to amortization over future years and may be reflected in future income statements.
Cumulative unrecognized actuarial losses for all plans were $268.4 million through December 31, 2019, compared with $280.9 million through December 31, 2018. These unrecognized losses reflect changes in the discount rates, differences between expected and actual asset returns, and changes to mortality expectations for plan participants, which are being amortized over future periods. These unrecognized losses may be recovered in future periods through actuarial gains. However, unless the minimum amount required to be amortized is below a corridor amount equal to 10.0% of the greater of the projected benefit obligation or the market-related value of plan assets, these unrecognized actuarial losses are required to be amortized and recognized in future periods. For example, projected pension plan expense for 2020 includes $10.4 million of amortization of these actuarial losses versus $10.8 million in 2019, $10.7 million in 2018 and $11.2 million in 2017.
Net periodic pension expense for our defined benefit pension plans is sensitive to changes in the underlying assumptions for the expected rates of return on plan assets and the discount rates used to determine the present value of projected benefits payable under the plans. If our assumptions for the expected returns on plan assets of our U.S. and U.K. defined benefit pension plans changed by 0.5%, representing either an increase or decrease in expected returns, the impact to 2019 consolidated pretax income would have been approximately $3.0 million. If our assumptions for the discount rates used to determine the present value of projected benefits payable under the plans changed by 0.25%, representing either an increase or decrease in interest rates used to value pension plan liabilities, the impact to 2019 consolidated pretax income would have been approximately $0.1 million. Net periodic pension expense is also sensitive to mortality assumptions. If the life expectancy of pension plan participants in our U.S. Qualified Plan was to increase or decrease by one year compared to current assumptions, our pension obligations would have changed by $15.1 million and our annual pension cost would have changed by $0.7 million, respectively.
We estimate the service and interest components of net periodic benefit cost for U.S. and international pension and other postretirement benefits. This approach discounts the individual expected cash flows underlying the service cost and interest cost using the applicable spot rates derived from the yield curve used to discount the cash flows used to measure the benefit obligation. For the pension plans, the weighted average spot rates used to determine interest costs were 2.72% for the Company’s U.S. plans and 1.71% for the U.K. plans.
## Income Taxes
We account for certain income and expense items differently for financial reporting and income tax purposes. Provisions for deferred taxes are made in recognition of these temporary differences. The most significant differences relate to accrued compensation and pensions, self-insurance, and depreciation and amortization.
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## CRAWFORD & COMPANY CONSOLIDATED BALANCE SHEETS (In thousands, except par value amounts)
<img src='content_image/1033627.jpg'>
The accompanying notes are an integral part of these consolidated financial statements.
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67,909
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https://cdla.io/permissive-1-0/
|
[
"content_image/1024799.jpg"
] |
overall_image/ff089309d724f1d0138c368de0b5f024803b0e5839a8ecc95d9e46e56ce48c2a.png
|
## Cash and Cash Equivalents
Cash and cash equivalents consist of cash on hand and marketable securities with original maturities of three months or less. The fair value of cash and cash equivalents approximates carrying value due to their short-term nature. At December 31, 2019, cash and cash equivalents included time deposits of approximately $931,000 that were in financial institutions outside the U.S.
## Accounts Receivable and Allowance for Doubtful Accounts
The Company extends credit based on an evaluation of a client's financial condition and, generally, collateral is not required. Accounts receivable are typically due upon receipt of the invoice and are stated on the Company's Consolidated Balance Sheets at amounts due from clients net of an estimated allowance for doubtful accounts. Accounts outstanding longer than the contractual payment terms are considered past due. The fair value of accounts receivable approximates book value due to their short-term contractual stipulations.
The Company maintains an allowance for doubtful accounts for estimated losses resulting primarily from the inability of clients to make required payments. Such losses are accounted for as bad debt expense, while adjustments to invoices are accounted for as reductions to revenue.
These allowances are established using historical write-off or adjustment information to project future experience and by considering the current creditworthiness of clients, any known specific collection problems, and an assessment of current industry and economic conditions. Actual experience may differ significantly from historical or expected loss results. The Company writes off accounts receivable when they become uncollectible, and any payments subsequently received are accounted for as recoveries. A summary of the activities in the allowance for doubtful accounts for the years ended December 31, 2019, 2018, and 2017 is as follows:
<img src='content_image/1024799.jpg'>
## Goodwill, Indefinite-Lived Intangible Assets, and Other Long-Lived Assets
Goodwill is an asset that represents the excess of the purchase price over the fair value of the separately identifiable net assets (tangible and intangible) acquired in certain business combinations. Indefinite-lived intangible assets consist of trade names associated with acquired businesses.
Goodwill and indefinite-lived intangible assets are not amortized, but are subject to impairment testing at least annually. Other long-lived assets consist primarily of property and equipment, deferred income tax assets, capitalized software, and amortizable intangible assets related to customer relationships, technology, and trade names with finite lives. Other long-lived assets are evaluated for impairment when impairment indicators are identified.
Subsequent to a business acquisition in which goodwill and indefinite-lived intangibles are recorded as assets, post-acquisition accounting requires that both be tested to determine whether there has been an impairment. The Company performs an impairment test of goodwill and indefinite-lived intangible assets at least annually on October 1 of each year. The Company regularly evaluates whether events and circumstances have occurred which indicate potential impairment of goodwill or indefinite-lived intangible assets. When factors indicate that such assets should be evaluated for possible impairment between the scheduled annual impairment tests, the Company performs an interim impairment test.
Goodwill impairment testing is performed on a reporting unit basis. If the fair value of the reporting unit exceeds its carrying value, including goodwill, goodwill is considered not impaired. If the carrying value of a reporting unit exceeds its fair value, an impairment loss shall be recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to that reporting unit. The loss recognized cannot subsequently be reversed.
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67,910
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https://cdla.io/permissive-1-0/
|
[
"content_image/1031526.jpg"
] |
overall_image/49d541799bc1f93b3f5a146f381a0b70c20e39339371f0e0b7c6505b1fdc8651.png
|
Property and equipment, including assets under finance leases, consisted of the following at December 31, 2019 and 2018:
<img src='content_image/1031526.jpg'>
Additions to property and equipment under finance leases, which are excluded from acquisitions of property and equipment in the Company's Statements of Cash Flows, totaled $760,000 for 2017. There were no such additions during 2019 or 2018.
Depreciation on property and equipment, including property under finance leases and amortization of leasehold improvements, was $11,363,000, $12,862,000, and $12,557,000 for the years ended December 31, 2019, 2018, and 2017, respectively.
## Capitalized Software
Capitalized software costs reflect costs related to internally developed or purchased software used by the Company that has expected future economic benefits. Certain internal and external costs incurred during the application development stage are capitalized. Costs incurred during the preliminary project and post implementation stages, including training and maintenance costs, are expensed as incurred. The majority of these capitalized software costs consist of internal payroll costs and external payments for software development, purchases and related services. These capitalized software costs are typically amortized over periods ranging from three to ten years, depending on the estimated life of each software application. Amortization expense for capitalized software was $17,873,000, $20,066,000, and $18,118,000 for the years ended December 31, 2019, 2018, and 2017, respectively.
## Self-Insured Risks
The Company self-insures certain risks consisting primarily of professional liability, auto liability, and employee medical, disability, and workers' compensation liability. Insurance coverage is obtained for catastrophic property and casualty exposures, including professional liability on a claims- made basis, and those risks required to be insured by law or contract. Most of these self-insured risks are in the U.S. Provisions for claims under the self-insured programs are made based on the Company's estimates of the aggregate liabilities for claims incurred, including estimated legal fees, losses that have occurred but have not been reported to the Company, and for adverse developments on reported losses. The estimated liabilities are calculated based on historical claims experience, the expected lives of the claims, and other factors considered relevant by management. Changes in these estimates may occur as additional information becomes available. The estimated liabilities for claims incurred under the Company's self-insured workers' compensation and employee disability programs are discounted at the prevailing risk-free interest rate for U.S. government securities of an appropriate duration. All other self-insured liabilities are undiscounted. At December 31, 2019 and 2018, accrued liabilities for self-insured risks totaled $26,838,000 and $29,078,000, respectively, including current liabilities of $11,311,000 and $15,246,000, respectively. The noncurrent liabilities are included in "Other noncurrent liabilities" on the Company's Consolidated Balance Sheets.
## Income Taxes
The Company accounts for certain income and expense items differently for financial reporting and income tax purposes. Provisions for deferred taxes are made in recognition of these temporary differences. The most significant differences relate to accrued compensation, pension plans, self-insurance, and depreciation and amortization.
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67,911
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https://cdla.io/permissive-1-0/
|
[
"content_image/1033690.jpg"
] |
overall_image/f5414d46e283531ac452d61351b3cdff55483e0feb6f58e065611605452ec32c.png
|
## Contract Balances
The timing of revenue recognition, billings and cash collections result in billed accounts receivables, contract assets (reported as unbilled revenues at estimated billable amounts) and contract liabilities (reported as deferred revenues) on the Company’s Consolidated Balance Sheets. Unbilled revenues is a contract asset for revenue that has been recognized in advance of billing the customer, resulting from professional services delivered that we expect and are entitled to receive as consideration under certain contracts. Billing requirements vary by contract but substantially all unbilled revenues are billed within one year.
When the Company receives consideration from a customer prior to transferring services to the customer under the terms of certain claims management agreements, it records deferred revenues on the Company’s Consolidated Balance Sheets, which represents a contract liability. These fixed-fee service agreements typically result from the Crawford TPA Solutions segment and require the Company to handle claims on either a one- or two-year basis, or for the lifetime of the claim. In cases where it handles a claim on a non-lifetime basis, the Company typically receives an additional fee on each anniversary date that the claim remains open. For service agreements where it provides services for the life of the claim, the Company is paid one upfront fee regardless of the duration of the claim. The Company recognizes deferred revenues as revenues as it performs services and transfers control of the services to the customer and satisfies the performance obligation which it determines utilizing a portfolio approach.
The Company's deferred revenues for claims handled for one or two years are not as sensitive to changes in claim closing rates since the performance obligations are satisfied within a fixed length of time. Deferred revenues for lifetime claim handling are more sensitive to changes in claim closing rates since the Company is obligated to handle these claims to conclusion with no additional fees received for long-lived claims. For all fixed fee service agreements, revenues are recognized over the expected service periods, by type of claim. Based upon its historical averages, the Company closes approximately 98% of all cases referred to it under lifetime claim service agreements within five years from the date of referral. Also, within that five-year period, the percentage of cases remaining open in any one particular year has remained relatively consistent from period to period. Each quarter the Company evaluates its historical case closing rates by type of claim utilizing a portfolio approach and makes adjustments to deferred revenues as necessary. As a portfolio approach is utilized to recognize deferred revenues, any changes in estimates will impact timing of revenue recognition and any changes in estimates are recognized in the period in which they are determined.
The table below presents the deferred revenues balance as of January 1, 2019 and the significant activity affecting deferred revenues during the year ended December 31, 2019:
<img src='content_image/1033690.jpg'>
## Remaining Performance Obligations
As of December 31, 2019, the Company had $88.6 million of remaining performance obligations related to claims and non-claims services in which the price is fixed. Remaining performance obligations consist of deferred revenues as well as certain unbilled receivables that are considered contract assets. The Company expects to recognize approximately 70% of our remaining performance obligations as revenues within one year and the remaining balance thereafter. See the discussion below regarding the practical expedients elected for the disclosure of remaining performance obligations.
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https://cdla.io/permissive-1-0/
|
[
"content_image/1041887.jpg",
"content_image/1041886.jpg"
] |
overall_image/3414023f649048bd2256831faa21e190218236e00f5ab51c6d5ae872e0f77e6b.png
|
Topic 740, No. 5, Accounting for Global Intangible Low-Taxed Income , states that an entity can make an accounting policy election to either recognize deferred taxes for temporary basis differences expected to reverse as GILTI in future years or to provide for the tax expense related to GILTI in the year the tax is incurred as a period expense only. At December 31, 2018, the Company elected to account for GILTI in the year the tax is incurred.
Deferred income taxes consisted of the following at December 31, 2019 and 2018:
<img src='content_image/1041887.jpg'>
At December 31, 2019, the Company had deferred tax assets related to loss carryforwards of $26,034,000, before netting of unrecognized tax benefits of $511,000. An estimated $16,342,000 of the deferred tax assets will not expire, and $9,692,000 will expire over the next 20 years if not utilized by the Company.
Changes in the Company's deferred tax valuation allowance are recorded as adjustments to the provision for income taxes. An analysis of the Company's deferred tax asset valuation allowances is as follows for the years ended December 31, 2019, 2018, and 2017.
<img src='content_image/1041886.jpg'>
Changes to the valuation allowance for the year ended December 31, 2019 were primarily due to anticipated expiration of certain state NOLs after consideration of the four sources of taxable income and losses in certain of the Company’s international operations. Changes to the valuation allowance for the year ended December 31, 2018 were primarily due to anticipated expiration of foreign tax credits after consideration of the Tax Act and the four sources of taxable income and losses in certain of the Company’s international and domestic operations. For the year ended December 31, 2017 the change was primarily due to losses in certain of the Company’s international operations and domestic operations impacting state NOLs.
|
67,913
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https://cdla.io/permissive-1-0/
|
[
"content_image/1059553.jpg",
"content_image/1059552.jpg"
] |
overall_image/dfafecc6a34cb8a81f081beded2dfc6a941c4e3ef1baa9ecbca9687a16b8e97c.png
|
The fair value of each option was estimated on the date of grant using the Black-Scholes-Merton option-pricing formula, with the following weighted average assumptions:
<img src='content_image/1059553.jpg'>
The expected dividend yield used for 2019 was based on the Company's historical dividend yield. The expected volatility of the price of CRD-A was based on historical realized volatility. The risk-free interest rate was based on the U.S. Treasury Daily Yield Curve Rate on the grant date, with a term equal to the expected term used in the pricing formula. The expected term of the option took into account both the contractual term of the option and the effects of expected exercise behavior.
## Performance-Based Stock Grants
Performance share grants are from time to time made to certain key employees of the Company. Such grants entitle employees to earn shares of CRD-A upon the achievement of certain individual and/or corporate objectives. Grants of performance shares are made at the discretion of the Company's Board of Directors, or the Board's Compensation Committee, and are subject to graded or cliff vesting over three-year periods. Shares are not issued until the vesting requirements have been met. Dividends are not paid or accrued on unvested/unissued shares. The grant-date fair value of a performance share grant is based on the market value of CRD-A on the date of grant, reduced for the present value of any dividends expected to be paid on CRD-A prior to the vesting of the award. Compensation expense for each award is recognized ratably from the grant date to the vesting date for each tranche.
A summary of the status of the Company's nonvested performance shares as of December 31, 2019, 2018, and 2017, and changes during each year, is presented below:
<img src='content_image/1059552.jpg'>
The total fair value of the performance shares that vested in 2019, 2018, and 2017 was $1,823,000, $2,662,000, and $3,597,000, respectively.
Compensation expense recognized for all performance shares totaled $1,082,000, $3,307,000, and $3,796,000 for the years ended December 31, 2019, 2018 and 2017, respectively. Compensation cost for these awards is net of estimated or actual award forfeitures. Certain performance awards vest ratably over three years, without cumulative earnings per share targets. As of December 31, 2019, there was an estimated $2,212,000 of unearned compensation cost for nonvested performance shares. This unearned compensation cost is expected to be fully recognized by the end of 2021.
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https://cdla.io/permissive-1-0/
|
[
"content_image/1046628.jpg"
] |
overall_image/c5051d897fbdbc1bf8d2d7ccfd57b8e81093b322ce8bfa5753dc0c8cb3f57a47.png
|
## Restricted Shares
The Company's Board of Directors may elect to issue restricted shares of CRD-A in lieu of, or in addition to, cash payments to certain key employees. Employees receiving these shares are subject to restrictions on their ability to transfer the shares. Such restrictions generally lapse ratably over vesting periods ranging from several months to five years. The grant-date fair value of a restricted share of CRD-A is based on the market value of the stock on the date of grant. Compensation cost is recognized on an accelerated basis over the requisite service period.
A summary of the status of the Company's restricted shares of CRD-A as of December 31, 2019, 2018, and 2017 and changes during each year, is presented below:
<img src='content_image/1046628.jpg'>
Compensation expense recognized for all restricted shares for the years ended December 31, 2019, 2018, and 2017 was $1,205,000, $1,176,000, and $1,205,000, respectively. As of December 31, 2019, there was $358,000 of total unearned compensation cost related to nonvested restricted shares which is expected to be recognized by June 30, 2021.
## Employee Stock Purchase Plans
The Company has three employee stock purchase plans: the U.S. Plan, the U.K. Plan, and the International Plan. Eligible employees in Canada, Puerto Rico, and the U.S. Virgin Islands may also participate in the U.S. Plan. The International Plan is for eligible employees located in certain other countries who are not covered by the U.S. Plan or the U.K. Plan. All plans are compensatory.
For all plans, the requisite service period is the period of time over which the employees contribute to the plans through payroll withholdings. For purposes of recognizing compensation expense, estimates are made for the total withholdings expected over the entire withholding period. The market price of a share of stock at the beginning of the withholding period is then used to estimate the total number of shares that will be purchased using the total estimated withholdings. Compensation cost is recognized ratably over the withholding period.
Under the U.S. Plan, the Company is authorized to issue up to 1,200,000 shares of CRD-A to eligible employees. Participating employees can elect to have up to $25,000 of their eligible annual earnings withheld to purchase shares at the end of the one-year withholding period which starts each July 1 and ends the following June 30. The purchase price of the stock is 85% of the lesser of the closing price of a share of such stock on the first day or the last day of the withholding period. Participating employees may cease payroll withholdings during the withholding period and/or request a refund of all amounts withheld before any shares are purchased.
|
67,915
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https://cdla.io/permissive-1-0/
|
[
"content_image/1031292.jpg"
] |
overall_image/6ecaa6d6aea3337f8a6f60c21143a67ee339285996a91af0ae9149d4523f6ae8.png
|
## Fair Value Measurements for Defined Benefit Pension Plan Assets
The fair value hierarchy is also applied to certain other assets that indirectly impact the Company's consolidated financial statements. Assets contributed by the Company to its defined benefit pension plans become the property of the individual plans. Even though the Company no longer has control over these assets, it is indirectly impacted by subsequent fair value adjustments to these assets. The actual return on these assets impacts the Company's future net periodic benefit cost, as well as amounts recognized in its Consolidated Balance Sheets. The Company uses the fair value hierarchy to measure the fair value of assets held by its U.S. and U.K. defined benefit pension plans.
The following table summarizes the level within the fair value hierarchy used to determine the fair value of the Company's pension plan assets for its U.S Qualified Plan at December 31, 2019 and 2018:
<img src='content_image/1031292.jpg'>
(a) net amounts payable for unsettled security transactions.
|
67,916
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https://cdla.io/permissive-1-0/
|
[
"content_image/1045420.jpg"
] |
overall_image/8046eea1d02d40f42d3544bac77d2a77a4d69632fc92cf0ab77829a09f77f7f2.png
|
The following table summarizes the level within the fair value hierarchy used to determine the fair value of the Company's pension plan assets for its U.K. plans at December 31, 2019 and 2018:
<img src='content_image/1045420.jpg'>
Short-term investment funds consist primarily of funds with a maturity of 60 days or less and are valued at amortized cost which approximates fair value.
Equity securities consist primarily of common collective funds (Level 2). Common collective funds are valued at the net asset value per share multiplied by the number of shares held as of the measurement date.
Fixed income securities consist of money market funds, government securities, corporate bonds and debt securities, mortgage-backed securities and other common collective funds. Government securities are valued by third-party pricing sources and are valued daily in an active market (Level 1). Corporate bonds are valued using either the yields currently available on comparable securities of issuers with similar credit ratings or using a discounted cash flows approach that utilizes observable inputs, such as current yields of similar instruments, and includes adjustments for valuation adjustments from internal pricing models which use observable inputs such as issuer details, interest rates, yield curves, default rates and quoted prices for similar assets (Level 2). Mortgage-backed securities are valued by pricing service providers that use broker-dealer quotations or valuation estimates from their internal pricing models (Level 2). Other common collective funds are valued at the net asset value per share multiplied by the number of shares held as of the measurement date (Level 2).
Alternative strategy funds valued at the net asset value per share multiplied by the number of shares held as of the measurement date (Level 2). Alternative strategy funds may include derivative instruments such as futures, forward contracts, options and swaps and are used to help manage risks. Derivative instruments are generally valued by the investment managers or in certain instances by third party pricing sources (Level 2) or may, due to the inherent uncertainty of valuation for those investments, differ significantly from the values that would have been used had a ready market for the investments existed, and the differences could be material (Level 3).
Real estate funds are primarily property unit trusts whose values are primarily reported by the fund manager and are based on valuation of the underlying investments which include inputs such as cost, discounted cash flows, independent appraisals and market-based comparable data (Level 3). The fair values may, due to the inherent uncertainty of valuation for those investments, differ significantly from the values that would have been used had a ready market for the investments existed, and the differences could be material.
|
67,917
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https://cdla.io/permissive-1-0/
|
[] |
overall_image/b06ced5d95165659b4317a3b8c10ecdfa0df97fbbdf55d6e62b6488f0bde5867.png
|
## Transportation
During the planning stage of our prospective and productive units and acreage, we consider required flow-lines, gathering and delivery infrastructure. Our oil is transported from the wellhead to our tank batteries or delivery points through our flow-lines or gathering systems. Purchasers of our oil take delivery at i) our tank batteries and transport the oil by truck, or ii) at a pipeline delivery point. Our natural gas is transported from the wellhead to the purchaser’s meter and pipeline interconnection point through our gathering systems.
In addition, we generally move the majority of our produced salt water by pipeline connected to our operated salt water disposal wells or by pipeline to commercial disposal facilities.
## Competition
The domestic oil and natural gas industry is intensely competitive in the acquisition of acreage, production and oil and gas reserves and in producing, transporting and marketing activities. Our competitors include national oil companies, major oil and natural gas companies, independent oil and natural gas companies, drilling partnership programs, individual producers, natural gas marketers, and major pipeline companies, as well as participants in other industries supplying energy and fuel to consumers. Many of our competitors are large, well-established companies. They may be able to pay more for seismic information and lease rights on oil and natural gas properties and to define, evaluate, bid for and purchase a greater number of properties, than our financial or human resources permit. Our ability to acquire additional properties in the future, and our ability to fund the acquisition of such properties, will be dependent upon our ability to evaluate and select suitable properties and to consummate related transactions in a highly competitive environment.
There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to absorb the burden of existing and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.
## Segment Information and Geographic Area
Operating segments are defined under accounting principles generally accepted in the United States (“GAAP”) as components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance.
Based on our organization and management, we have only one reportable operating segment, which is oil and natural gas acquisition, exploration, development and production. All of our operations are currently conducted in Texas.
## Seasonality of Business
Weather conditions often affect the demand for, and prices of, natural gas and can also delay oil and natural gas drilling activities, disrupting our overall business plans. Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices for our natural gas production during our first and fourth fiscal quarters. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that we may realize on an annual basis.
## Markets for Sale of Production
Our ability to market oil and natural gas found and produced, depends on numerous factors beyond our control, the effect of which cannot be accurately predicted or anticipated. Some of these factors include, without limitation, the availability of other domestic and foreign production, the marketing of competitive fuels, the proximity and capacity of pipelines, fluctuations in supply and demand, the availability of a ready market, the effect of United States federal and state regulation of production, refining, transportation and sales and general national and worldwide economic conditions. Additionally, we may experience delays in marketing natural gas production and fluctuations in natural gas prices and we may experience short-term delays in marketing oil due to trucking and refining constraints. There is no assurance that we will be able to market any oil or natural gas produced, or, if such oil or natural gas is marketed, that favorable prices can be obtained.
The United States natural gas market has undergone several significant changes over the past few decades. The majority of federal price ceilings were removed in 1985 and the remainder were lifted by the Natural Gas Wellhead Decontrol Act of 1989. Thus, currently, the United States natural gas market is operating in a free market environment in which the price of gas is determined
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by market forces rather than by regulations. At the same time, the domestic natural gas industry has also seen a dramatic change in the manner in which gas is bought, sold and transported. In most cases, natural gas is no longer sold to a pipeline company. Instead, the pipeline company now primarily serves the role of transporter and gas producers are free to sell their product to marketers, local distribution companies, end users or a combination thereof.
In recent years, oil, natural gas and NGLs prices have been under considerable pressure due to oversupply and other market conditions. Specifically, increased foreign production and increased efficiencies in horizontal drilling, combined with exploration of newly developed shale fields in North America, have dramatically increased global oil and natural gas production, which has led to significantly lower market prices for these commodities. In view of the many uncertainties affecting the supply and demand for oil, natural gas and NGLs, we are unable to accurately predict future oil, natural gas and NGLs prices or the overall effect, if any, that the decline in demand for and the oversupply of such products will have on our financial condition or results of operations.
## Title to Properties
We believe that the title to our oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and natural gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of our oil and natural gas properties. Our oil and natural gas properties are typically subject, in one degree or another, to one or more of the following:
• royalties and other burdens and obligations, express or implied, under oil and natural gas leases;
• overriding royalties and other burdens created by us or our predecessors in title;
• a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farmout agreements, participation agreements, production sales contracts and other agreements that may affect the properties or their titles;
• back-ins and reversionary interests existing under various agreements and leasehold assignments;
• liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements;
• pooling, unitization and other agreements, declarations and orders; and
• easements, restrictions, rights-of-way and other matters that commonly affect property.
To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account in calculating our net revenue interests and in estimating the quantity and value of our reserves. We believe that the burdens and obligations affecting our oil and natural gas properties are common in our industry with respect to the types of properties we own.
## Operational Regulations
All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory and regulatory provisions affecting drilling, completion, and production activities, including, but not limited to, provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the plugging and abandonment of wells. Our operations are also subject to various conservation laws and regulations. These laws and regulations govern the size of drilling and spacing units, the density of wells that may be drilled in oil and natural gas properties and the unitization or pooling of oil and natural gas properties. In this regard, while some states allow the forced pooling or integration of land and leases to facilitate development, other states including Texas, where we operate, rely primarily or exclusively on voluntary pooling of land and leases. Accordingly, it may be difficult for us to form spacing units and therefore difficult to develop a project if we own or control less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose specified requirements regarding the ratability of production. On some occasions, local authorities have imposed moratoria or other restrictions on exploration, development and production activities pending investigations and studies addressing potential local impacts of these activities before allowing oil and natural gas exploration, development and production to proceed.
The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.
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## Regulation of Transportation of Natural Gas
The transportation and sale, or resale, of natural gas in interstate commerce are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
## Regulation of Sales of Oil, Natural Gas and Natural Gas Liquids
The prices at which we sell oil, natural gas and natural gas liquids are not currently subject to federal regulation and, for the most part, are not subject to state regulation. FERC, however, regulates interstate natural gas transportation rates, and terms and conditions of transportation service, which affects the marketing of the natural gas we produce, as well as the prices we receive for sales of our natural gas. Similarly, the price we receive from the sale of oil and natural gas liquids is affected by the cost of transporting those products to market. FERC regulates the transportation of oil and liquids on interstate pipelines under the provision of the Interstate Commerce Act, the Energy Policy Act of 1992 and regulations issued under those statutes. Intrastate transportation of oil, natural gas liquids, and other products, is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. In addition, while sales by producers of natural gas and all sales of crude oil, condensate, and natural gas liquids can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.
Changes in FERC or state policies and regulations or laws may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action that FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.
## Environmental Regulations
Our operations are also subject to stringent federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. Numerous governmental agencies, such as the United States Environmental Protection Agency (the “EPA”) issue regulations to implement and enforce these laws, which often require difficult and costly compliance measures. Among other things, environmental regulatory programs typically govern the permitting, construction and operation of a well or production related facility. Many factors, including public perception, can materially impact the ability to secure an environmental construction or operation permit. Failure to comply with environmental laws and regulations may result in the assessment of substantial administrative, civil and criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities. In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, which could result in liability for environmental damages and cleanup costs without regard to negligence or fault on our part.
Beyond existing requirements, new programs and changes in existing programs, may affect our business including oil and natural gas exploration and production, air emissions, waste management, and underground injection of waste material. Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect on our financial condition and results of operations. The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance in the future may have a material adverse impact on our capital expenditures, earnings and competitive position.
## Hazardous Substances and Wastes
The federal Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct on certain categories of persons that are considered to be responsible for the release of a hazardous substance into the environment. These persons may include the current or former owner or operator of the site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances found at the site. Under CERCLA, these potentially responsible persons may be subject to strict, joint and several liability for the costs of investigating and cleaning up hazardous substances that
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and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges.
Our oil and natural gas production also generates salt water, which we dispose of by underground injection. The federal Safe Drinking Water Act (“ SDWA ”) regulates the underground injection of substances through the Underground Injection Control (“ UIC ”) program, and related state programs regulate the drilling and operation of salt water disposal wells. The EPA directly administers the UIC program in some states, and in others it is delegated to the state for administering. In Texas, the Texas Railroad Commission (“ RRC ”) regulates the disposal of produced water by injection well. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking salt water to groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In response to recent seismic events near underground injection wells used for the disposal of oil and natural gas-related waste waters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or placed volumetric injection limits on existing wells or imposed moratoria on the use of such injection wells. In response to concerns related to induced seismicity, regulators in some states have already adopted or are considering additional requirements related to seismic safety. For example, the RRC has adopted rules for injection wells to address these seismic activity concerns in Texas. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. More stringent regulation of injection wells could lead to reduced construction or the capacity of such wells, which could in turn impact the availability of injection wells for disposal of wastewater from our operations. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability. The costs associated with the disposal of proposed water are commonly incurred by all oil and natural gas producers, however, and we do not believe that these costs will have a material adverse effect on our operations. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.
## Hydraulic Fracturing
Our completion operations are subject to regulation, which may increase in the short- or long-term. In particular, the well completion technique known as hydraulic fracturing is used to stimulate production of oil and natural gas has come under increased scrutiny by the environmental community, and many local, state and federal regulators. Hydraulic fracturing involves the injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depths to stimulate oil and natural gas production. We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with substantially all of the wells for which we are the operator.
The SDWA regulates the underground injection of substances through the UIC program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. However, legislation has been proposed in recent sessions of Congress to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process.
Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the fracturing process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells.
In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment (“CWT”) facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.
In addition, on March 26, 2015, the Bureau of Land Management (the “BLM”) published a final rule governing hydraulic fracturing on federal and Indian lands. Also, on November 15, 2016, the BLM finalized a waste preventing rule to reduce the flaring, venting and leaking of methane from oil and natural gas operations on federal and Indian lands. On March 28, 2017, President Trump signed an executive order directing the BLM to review the above rules and, if appropriate, to initiate a rulemaking to rescind or revise them. Accordingly, on December 29, 2017, the BLM published a final rule to rescind the 2015 hydraulic fracturing rule; however, a coalition of environmentalists, tribal advocates and the state of California filed lawsuits challenging the rule rescission. Also, on February 22, 2018, the BLM published proposed amendments to the waste prevention rule that would eliminate certain air quality provisions and, on April 4, 2018, a federal district court stayed certain provisions of the 2016 rule. At this time, it is uncertain when, or if, the rules will be implemented, and what impact they would have on our operations.
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implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.
## Climate Change
In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) endanger public health and the environment, the EPA has adopted regulations under existing provisions of the Clean Air Act that, among other things, establish Prevention of Significant Deterioration (“PSD”), construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards for these emissions. EPA rulemakings related to GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the annual reporting of GHG emissions from certain petroleum and natural gas system sources in the U.S., including, among others, onshore and offshore production facilities, which include certain of our operations. Also, as noted above, the EPA has promulgated a New Source Performance Standard related to methane emissions from the oil and natural gas source category.
While Congress has considered legislation related to the reduction of GHG emissions in the past, no significant legislation to reduce GHG emissions has been adopted at the federal level. In the absence of Congressional action, a number of state and regional GHG restrictions have emerged. At the international level, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement entered into force in November 2016. Although this agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges from participating nations to voluntarily limit or reduce future emissions. In June 2017, President Trump stated that the United States would withdraw from the Paris Agreement, but may enter into a future international agreement related to GHGs. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain, and the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations.
Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of and value of our products and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. Currently, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Finally, it should also be noted that many scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic events; if any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
## National Environmental Policy Act
Oil and natural gas exploration, development and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions that have the potential to significantly impact the environment. The process involves the preparation of either an environmental assessment or environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the human environment. The NEPA process involves public input through comments which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This process may result in delaying the permitting and development of projects, increase the costs of permitting and developing some facilities and could result in certain instances in the cancellation of existing leases.
## Threatened and endangered species, migratory birds and natural resources
Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act (“ ESA ”), the Migratory Bird Treaty Act and the Clean Water Act. The U.S. Fish and Wildlife Service (“ FWS ”) may designate critical habitat areas that it believes are necessary for survival of threatened or endangered species. As a result of a 2011 settlement agreement, the FWS was
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## Employees
As of December 31, 2018, we had 65 full-time employees, of which nine are management, 19 are technical personnel, 19 are administrative personnel and 18 are field operations employees. Our employees are not covered under a collective bargaining agreement nor are any employees represented by a union. We consider all relations with our employees to be satisfactory.
## Office Leases
As of December 31, 2018, we leased office space as set forth in the following table:
<img src='content_image/1042348.jpg'>
During 2018, aggregate rental payments for our office facilities totaled approximately $0.9 million.
## Executive Officers of the Company
The following table sets forth, as of March 1, 2019, certain information regarding the executive officers of Earthstone:
<img src='content_image/1042349.jpg'>
The following biographies describe the business experience of our executive officers:
$^{ }$Frank A. Lodzinski has served as our Chairman and Chief Executive Officer since December 2014. He also served as our President from December 2014 through April 2018. Previously, he served as President and Chief Executive Officer of Oak Valley Resources, LLC (“Oak Valley”) from its formation in December 2012 until the closing of its strategic combination with Earthstone in December 2014. Prior to his service with Oak Valley, Mr. Lodzinski was Chairman, President and Chief Executive Officer of GeoResources, Inc. from April 2007 until its merger with Halcón Resources Corporation (“Halcón”) in August 2012 and from September 2012 until December 2012 he conducted pre-formation activities for Oak Valley. He has over 45 years of oil and gas industry experience. In 1984, he formed Energy Resource Associates, Inc., which acquired management and controlling interests in oil and gas limited partnerships, joint ventures and producing properties. Certain partnerships were exchanged for common shares of Hampton Resources Corporation in 1992, which Mr. Lodzinski joined as a director and President. Hampton was sold in 1995 to Bellwether Exploration Company. In 1996, he formed Cliffwood Oil & Gas Corp. and in 1997, Cliffwood shareholders acquired a controlling interest in Texoil, Inc., where Mr. Lodzinski served as Chief Executive Officer and President. In 2001, Mr. Lodzinski was appointed Chief Executive Officer and President of AROC, Inc., to direct the restructuring and ultimate liquidation of that company. In 2003, AROC completed a monetization of oil and gas assets with an institutional investor and began a plan of liquidation in 2004. In 2004, Mr. Lodzinski formed Southern Bay Energy, LLC, the general partner of Southern Bay Oil & Gas, L.P., which acquired the residual assets of AROC, Inc., and he served as President of Southern Bay Energy, LLC upon its formation. The Southern Bay entities were merged into GeoResources in April 2007. Mr. Lodzinski has served as a director and member of the compensation committee of Yuma Energy, Inc. since October 2016 and previously served on its audit committee from September 2014 to October 2016. He holds a BSBA degree in Accounting and Finance from Wayne State University in Detroit, Michigan.
$^{ }$Robert J. Anderson is a petroleum engineer with over 30 years of diversified domestic and international oil and gas experience. He has served as our President since April 2018. From December 2014 through April 2018, he served as our Executive Vice President, Corporate Development and Engineering. Previously, he served in a similar capacity with Oak Valley from March 2013 until the closing of its strategic combination with Earthstone in December 2014. Prior to joining Oak Valley, he served from August 2012 to February 2013 as Executive Vice President and Chief Operating Officer of Halcón. Mr. Anderson was employed by GeoResources, Inc. from April 2007 until its merger with Halcón in August 2012, ultimately serving as a director and Executive Vice President, Chief Operating Officer - Northern Region. He was involved in the formation of Southern Bay Energy in September 2004 as Vice President, Acquisitions until its merger with GeoResources in April 2007. From March 2004 to August 2004, Mr. Anderson was employed by AROC, a predecessor company to Southern Bay Energy, as Vice President, Acquisitions and Divestitures. From September 2000 to February 2004, he was employed by Anadarko Petroleum Corporation as a petroleum
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engineer. In addition, he has worked with major oil companies, including ARCO International/Vastar Resources, and independent oil companies, including Hunt Oil, Hugoton Energy, and Pacific Enterprises Oil Company. His professional experience includes acquisition evaluation, reservoir and production engineering, field development, project economics, budgeting and planning, and capital markets. His domestic acquisition and divestiture experience includes Texas and Louisiana (offshore and onshore), Mid-Continent, and the Rocky Mountain states, and his international experience includes Canada, South America, and Russia. Mr. Anderson has a B.S. degree in Petroleum Engineering from the University of Wyoming and an MBA from the University of Denver.
$^{ }$Tony Oviedo has served as our Executive Vice President - Accounting and Administration (Principal Accounting Officer) since February 10, 2017. Mr. Oviedo has over 30 years of professional experience with both private and public companies. Prior to joining the Company, he was employed by GeoMet, Inc., where, since 2006, he served as the Senior Vice President, Chief Financial Officer, Chief Accounting Officer and Controller. In addition, prior to joining GeoMet, Mr. Oviedo was employed by Resolution Performance Products, LLC, where he was Compliance Director and has held positions as Chief Accounting Officer, Controller, and Director of Financial Reporting with various companies in the oil and gas industry. Prior to the aforementioned experience, he served in the audit practice of KPMG LLP’s Energy Group. Mr. Oviedo holds a Bachelor’s degree in Business Administration with a concentration in accounting and tax from the University of Houston and is a Certified Public Accountant in the state of Texas.
Mark Lumpkin, Jr. has over 21 years of experience including over 14 years of oil and gas finance experience. He has served as our Executive Vice President and Chief Financial Officer since August 2017. Immediately prior to joining Earthstone, he served as Managing Director at RBC Capital Markets in the Oil and Gas Corporate Banking group, beginning in 2011 with a focus on upstream and midstream debt financing. From 2006 until 2011, he was employed by The Royal Bank of Scotland (“RBS”) in the Oil and Gas group within the Corporate and Investment Banking division, focusing primarily on the upstream subsector. Prior to RBS, he spent two years focused on capital markets and mergers and acquisitions primarily in the upstream sector at a boutique investment bank. Mr. Lumpkin graduated with a B.A. degree in Economics from Louisiana State University and graduated with a Master of Business Administration degree with a Finance concentration from Tulane University.
$^{ }$Steven C. Collins is a petroleum engineer with over 29 years of operations and related experience. He has served as our Executive Vice President, Completions and Operations since December 2014. Previously, he served in a similar capacity with Oak Valley from its formation in December 2012 until the closing of its strategic combination with Earthstone in December 2014. Prior to employment by Oak Valley, he served from August 2012 to November 2012 as a consultant to Halcón. Mr. Collins was employed by GeoResources, Inc. from April 2007 until its merger with Halcón in August 2012 and directed field operations, including well completion, production and workover operations. Prior to employment by GeoResources, he served as Vice President of Operations for Southern Bay, AROC, and Texoil, and as a petroleum and operations engineer at Hunt Oil Company and Pacific Enterprises Oil Company. His experience includes Texas, Louisiana (onshore and offshore), North Dakota, Montana, and the Mid-Continent. Mr. Collins graduated with a B.S. degree in Petroleum Engineering from the University of Texas.
$^{ }$Timothy D. Merrifield has over 38 years of oil and gas industry experience. He has served as our Executive Vice President, Geology and Geophysics since December 2014. Previously, he served in a similar capacity with Oak Valley from its formation in December 2012 until the closing of its strategic combination with Earthstone in December 2014. Prior to employment by Oak Valley, he served from August 2012 to November 2012 as a consultant to Halcón upon its merger with GeoResources, Inc. in August 2012. From April 2007 to August 2012, Mr. Merrifield led all geology and geophysics efforts at GeoResources. He has held previous roles at AROC, Forcenergy, Great Western Resources and other independents. His domestic experience includes Texas, Louisiana (onshore and offshore), North Dakota, Montana, New Mexico, Rocky Mountain States, and the Mid- Continent. In addition, he has international experience in Peru and the East Irish Sea. Mr. Merrifield attended Texas Tech University.
$^{ }$Francis M. Mury has over 43 years of oil and gas industry experience. He has served as our Executive Vice President, Drilling and Development since December 2014. Previously, he served in a similar capacity with Oak Valley from its formation in December 2012 until the closing of its strategic combination with Earthstone in December 2014. Prior to employment by Oak Valley, he was employed by GeoResources, Inc. from April 2007 until its merger with Halcón in August 2012, ultimately serving as an Executive Vice President, Chief Operating Officer–Southern Region. He has held prior roles at AROC, Texoil, Hampton Resources, Wainoco Oil & Gas Company, Diasu Exploration Company, and Texaco, Inc. His experience extends to all facets of petroleum engineering, including reservoir engineering, drilling and production operations, petroleum economics, geology, geophysics, land, and joint operations. Geographical areas of experience include Texas and Louisiana (offshore and onshore), North Dakota, Montana, Mid-Continent, Florida, New Mexico, Oklahoma, Wyoming, Pennsylvania and Michigan. Mr. Mury graduated from Nicholls State University with a degree in Computer Science.
## Available Information
Our principal executive offices are located at 1400 Woodloch Forest Drive, Suite 300, The Woodlands, Texas 77380. Our telephone number is (281) 298-4246. You can find more information about us at our website located at www.earthstoneenergy.com. Our
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## CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
Certain statements contained in this report may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts contained in this report are forward-looking statements. These forward-looking statements can generally be identified by the use of words such as “may,” “will,” “could,” “should,” “project,” “intends,” “plans,” “pursue,” “target,” “continue,” “believes,” “anticipates,” “expects,” “estimates,” “guidance,” “predicts,” or “potential,” the negative of such terms or variations thereon, or other comparable terminology. Statements that describe our future plans, strategies, intentions, expectations, objectives, goals, potential acquisitions or mergers or prospects are also forward-looking statements. Actual results could differ materially from those anticipated in this filing or these forward-looking statements. Readers should consider carefully the risks described under the “Risk Factors” section of this report and other sections of this report which describe factors that could cause our actual results to differ from those anticipated in forward-looking statements, including, but not limited to, the following factors:
• continued volatility and weakness in commodity prices for oil, natural gas and natural gas liquids and the effect of prices set or influenced by action of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil and natural gas producing countries;
• substantial changes in estimates of our proved reserves;
• substantial declines in the estimated values of our proved oil and natural gas reserves;
• our ability to replace our oil and natural gas reserves;
• the risk of the actual presence or recoverability of oil and natural gas reserves and that future production rates will be less than estimated;
• the potential for production decline rates and associated production costs for our wells to be greater than we forecast;
• the timing and extent of our success in developing, acquiring, discovering and producing oil and natural gas reserves;
• the ability and willingness of our partners under our joint operating agreements to join in our plans for future exploration, development and production activities;
• our ability to acquire additional mineral leases;
• the cost and availability of high quality goods and services with fully trained and adequate personnel, such as contract drilling rigs and completion equipment on a timely basis and at reasonable prices;
• risks in connection with potential acquisitions and the integration of significant acquisitions or assets acquired through merger or otherwise;
• the possibility that acquisitions and divestitures may involve unexpected costs or delays, and that acquisitions may not achieve intended benefits;
• the possibility that potential divestitures may not occur or could be burdened with unforeseen costs;
• unanticipated reductions in the borrowing base under the credit agreement we are party to;
• risks incidental to the drilling and operation of oil and natural gas wells including mechanical failures;
• our dependence on the availability, use and disposal of water in our drilling, completion and production operations;
• the availability of sufficient pipeline and other transportation facilities to carry our production to market and the impact of these facilities on realized prices;
• significant competition for oil and natural gas acreage and acquisitions;
• the effect of existing and future laws, governmental regulations and the political and economic climates of the United States particularly with respect to climate change, alternative energy and similar topical movements;
• our ability to retain key members of senior management and key technical and financial employees;
• changes in environmental laws and the regulation and enforcement related to those laws;
• the identification of and severity of adverse environmental events and governmental responses to these or other environmental events;
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Annual Report on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and any amendments to those reports are available free of charge on or through our website, which is not part of this report. These reports are available as soon as reasonably practicable after we electronically file these materials with, or furnish them to, the SEC. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us.
## Item 1A. Risk Factors
Our business is subject to various risks and uncertainties in the ordinary course of our business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition or results of operations. We cannot assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. When considering an investment in our shares of Class A Common Stock, you should carefully consider the risk factors included below as well as those matters referenced in this report under “Cautionary Statement Concerning Forward-Looking Statements” and other information included and incorporated by reference into this report.
## Oil, natural gas and natural gas liquids prices are volatile. Their prices at times since 2014 have adversely affected, and in the future may adversely affect, our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments. Volatile and lower prices may also negatively impact our stock price.
The prices we receive for our oil, natural gas and natural gas liquids production heavily influence our revenues, profitability, access to capital and future rate of growth. These hydrocarbons are commodities, and therefore, their prices may be subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the market for oil, natural gas and natural gas liquids has been volatile. For example, during the period from January 1, 2014 through December 31, 2018, the West Texas Intermediate (“WTI”) spot price for oil declined from a high of $107.95 per Bbl in June 2014 to $26.19 per Bbl in February 2016. The Henry Hub spot price for natural gas has declined from a high of $8.15 per MMBtu in February 2014 to a low of $1.49 per MMBtu in March 2016. During 2018, WTI spot prices ranged from $44.48 to $77.41 per Bbl and the Henry Hub spot price of natural gas ranged from $2.49 to $6.24 per MMBtu. Likewise, natural gas liquids, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different pricing characteristics, have experienced significant declines in realized prices since the fall of 2014. The prices we receive for oil, natural gas and natural gas liquids we produce and our production levels depend on numerous factors beyond our control, including:
• worldwide and regional economic and financial conditions impacting global and regional supply and demand;
• the level of global exploration, development and production;
• the level of global supplies, in particular due to supply growth from the United States;
• the price and quantity of oil, natural gas and NGLs imports to and exports from the U.S.;
• political conditions in or affecting other oil, natural gas and natural gas liquids producing countries and regions, including the current conflicts in the Middle East, as well as conditions in South America, Africa and Eastern Europe;
• actions of the OPEC and state-controlled oil companies relating to production and price controls;
• the extent to which U.S. shale producers become swing producers adding or subtracting to the world supply totals;
• future regulations prohibiting or restricting our ability to apply hydraulic fracturing to our wells;
• current and future regulations regarding well spacing;
• prevailing prices and pricing differentials on local oil, natural gas and natural gas liquids price indices in the areas in which we operate;
• localized and global supply and demand fundamentals and transportation, gathering and processing availability;
• weather conditions;
• technological advances affecting fuel economy, energy supply and energy consumption;
• the effect of energy conservation measures, alternative fuel requirements and increasing demand for alternatives to oil and natural gas;
• the price and availability of alternative fuels; and
• domestic, local and foreign governmental regulation and taxes.
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relating to development of our properties, which in turn could lead to a decline in our reserves and production and would adversely affect our business, financial condition and results of operations.
## A negative shift in investor sentiment towards the oil and gas industry could adversely affect our ability to raise equity and debt capital.
Certain segments of the investor community have recently developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. Some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and gas sector based on social and environment considerations. Certain other stakeholders have pressured commercial and investment banks to stop funding oil and gas projects. Such developments could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results.
## We have incremental cash inflows and outflows as a result of our hedging activities. To the extent we are unable to obtain future hedges at attractive prices or our derivative activities are not effective, our cash flows and financial condition may be adversely impacted.
In an effort to achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we often enter into derivative instrument contracts for a portion of our oil and natural gas production, including swaps, collars, puts and basis swaps. We recognize all derivatives as either assets or liabilities, measured at fair value, and recognize changes in the fair value of derivatives in current earnings. Accordingly, our earnings may fluctuate significantly and our results of operations may be significantly and adversely affected because of changes in the fair market value of our derivative instruments. As our derivative instrument contracts expire, there is no assurance that we will be able to replace them comparably.
Derivative instruments can expose us to the risk of financial loss in varying circumstances, including, but not limited to, when:
• production is less than the volume covered by the derivative instruments;
• the counter-party to the derivative instrument defaults on its contractual obligations;
• there is an increase in the differential between the underlying price stated in the derivative instrument contract and actual prices received; or
• there are issues with regard to legal enforceability of such instruments.
For additional information regarding our hedging activities, please see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 6. Derivative Financial Instruments in the Notes to Consolidated Financial Statements included in this report for additional information.
## Derivatives reform legislation and related regulations could have an adverse effect on our ability to hedge risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission (the "CFTC"), the SEC, and federal regulators of financial institutions adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act.
The CFTC has finalized other regulations implementing the Dodd-Frank Act's provisions regarding trade reporting, margin, clearing, and trade execution; however, some regulations remain to be finalized and it is not possible at this time to predict when the CFTC will adopt final rules. For example, the CFTC has re-proposed regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions are expected to be made exempt from these limits. Also, it is possible that under recently adopted margin rules, some registered swap dealers may require us to post initial and variation margins in connection with certain swaps not subject to central clearing.
The Dodd-Frank Act and any additional implementing regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, limit our ability to trade some derivatives to hedge risks, reduce the availability of some derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing commodity derivative contracts. If we reduce our use of derivatives as a consequence, 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 expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading
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in derivatives and commodity instruments related to oil and natural gas. If the implementing regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations.
## The oil and natural gas industry is highly competitive, and our small size puts us at a disadvantage in competing for resources.
The oil and natural gas industry is highly competitive particularly in the Permian Basin of Texas where our properties and operations are concentrated. We compete with major integrated and larger independent oil and natural gas companies in seeking to acquire desirable oil and natural gas properties and leases and for the equipment and services required to develop and operate properties. Many of our competitors have financial and other resources that are substantially greater than ours, which makes acquisitions of acreage or producing properties at economic prices difficult. Significant competition also exists in attracting and retaining technical personnel, including geologists, geophysicists, engineers, landmen and other specialists, as well as financial and administrative personnel hence we may be at a competitive disadvantage to companies with larger financial resources than ours.
## Failure to complete additional acquisitions could limit our potential growth.
Our future success is highly dependent on our ability to acquire and develop mineral leases and oil and gas properties with economically recoverable oil and natural gas reserves. Without continued successful acquisition, of economic development projects, our current estimated oil and natural gas reserves will decline due to continued production activities. Acquiring additional oil and natural gas properties, or businesses that own or operate such properties is an important component of our business strategy. If we identify an appropriate acquisition candidate, management may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. Our limited access to financial resources compared to larger, better capitalized companies may limit our ability to make future acquisitions. If we are unable to complete suitable acquisitions, it may be more difficult to replace and increase our reserves, and an inability to replace our reserves may have a material adverse effect on our financial condition and results of operations.
## Acquisitions involve a number of risks, including the risk that we will discover unanticipated liabilities or other problems associated with the acquired business or property.
In assessing potential acquisitions, we consider information available in the public domain and information provided by the seller. In the event publicly available data is limited, then, by necessity, we may rely to a large extent on information that may only be available from the seller, particularly with respect to drilling and completion costs and practices, geological, geophysical and petrophysical data, detailed production data on existing wells, and other technical and cost data not available in the public domain. Accordingly, the review and evaluation of businesses or properties to be acquired may not uncover all existing or relevant data, obligations or actual or contingent liabilities that could adversely impact any business or property to be acquired and, hence, could adversely affect us as a result of the acquisition. These issues may be material and could include, among other things, unexpected environmental liabilities, title defects, unpaid royalties, taxes or other liabilities. If we acquire properties on an “as-is” basis, we may have limited or no remedies against the seller with respect to these types of problems.
The success of any acquisition that we complete will depend on a variety of factors, including our ability to accurately assess the reserves associated with the acquired properties, assumptions related to future oil and natural gas prices and operating costs, potential environmental and other liabilities and other factors. These assessments are often inexact and subjective. As a result, we may not recover the purchase price of a property from the sale of production from the property or recognize an acceptable return from such sales or operations.
Our ability to achieve the benefits that we expect from an acquisition will also depend on our ability to efficiently integrate the acquired operations. Management may be required to dedicate significant time and effort to the integration process, which could divert its attention from other business opportunities and concerns. The challenges involved in the integration process may include retaining key employees and maintaining employee morale, addressing differences in business cultures, processes and systems and developing internal expertise regarding acquired properties.
## We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations, including our drilling operations.
Oil and natural gas exploration, development and production activities are subject to numerous significant operating risks, including the possibility of:
• unanticipated, abnormally pressured formations;
• significant mechanical difficulties, such as stuck drilling and service tools and casing collapses;
• blowouts, fires and explosions;
• personal injuries and death;
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federal, state and local income taxes and non-U.S. tax liabilities of Earthstone, Lynden Corp and Lynden US, if any, at assumed tax rates. We will likely be limited, however, in our ability to cause EEH and its subsidiaries to make these and other distributions due to the restrictions under an agreement providing for our senior secured revolving credit facility (the “EEH Credit Agreement”). To the extent that we need funds, and EEH or its subsidiaries are restricted from making such distributions under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition.
## We are a “controlled company” within the meaning of the NYSE rules and, as a result, qualify for and rely on exemptions from certain corporate governance requirements.
EnCap controls a majority of the combined voting power of all classes of our outstanding voting stock. As a result, we are a controlled company within the meaning of the NYSE corporate governance standards. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a controlled company and may elect not to comply with certain NYSE corporate governance requirements, including the requirements that:
• a majority of the board of directors consist of independent directors;
• the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and
• the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.
These requirements will not apply to us as long as we remain a controlled company. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE.
## Our principal stockholders hold a substantial majority of the voting power of our Class A Common Stock and Class B Common Stock.
Holders of Class A Common Stock and Class B Common Stock will vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or our Third Amended and Restated Certificate of Incorporation. EnCap may be deemed to beneficially own approximately 61.1% of our voting interests. As a significant stockholder, EnCap and certain of its affiliates could limit the ability of our other stockholders to approve transactions they may deem to be in the best interests of our Company or delaying or preventing changes in control or changes in our management.
As long as EnCap and certain of its affiliates continue to control a significant amount of our outstanding voting securities, they will have the authority to exercise significant influence over management and all matters requiring stockholder approval, regardless of whether or not other stockholders believe that a potential transaction is in their own best interests. Also, in any of these matters, the interests of our management team may differ or conflict with the interests of our stockholders. In addition, EnCap and its affiliates may, from time to time, acquire interests in businesses that directly or indirectly compete with our business, as well as businesses that are significant existing or potential acquisition candidates or industry partners. EnCap and its affiliates may acquire or seek to acquire assets that we seek to acquire and, as a result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue. Moreover, this concentration of stock ownership may also adversely affect the trading price of our Class A Common Stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling stockholder.
## Future sales of our Class A Common Stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity may dilute your ownership in us.
We may sell additional shares of Class A Common Stock or securities convertible into shares of our Class A Common Stock in subsequent offerings. We cannot predict the size of future issuances of our Class A Common Stock or securities convertible into Class A Common Stock or the effect, if any, that future issuances and sales of shares of our Class A Common Stock will have on the market price of our Class A Common Stock. Sales of substantial amounts of our Class A Common Stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A Common Stock.
## Bold Holdings and its permitted transferees have the right to exchange their EEH Units and shares of Class B Common Stock for our Class A Common Stock pursuant to the terms of the EEH LLC Agreement.
As of March 1, 2019, there were approximately 35.5 million shares of our Class A Common Stock that are issuable upon redemption or exchange of EEH Units and shares of Class B Common Stock that are held by Bold Holdings or its permitted transferees. Pursuant to the EEH LLC Agreement, subject to certain restrictions therein, holders of EEH Units and our Class B Common Stock are entitled to exchange such EEH Units and shares of Class B Common Stock for shares of our Class A Common Stock at any time. We also entered into a registration rights agreement pursuant to which the shares of Class A Common Stock which may be
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• speculation in the press or investment community regarding our business;
• political conditions in oil and natural gas producing regions of the world;
• general market and economic conditions; and
• domestic and international economic, legal, and regulatory factors unrelated to our performance.
In addition, U.S. securities markets have experienced significant price and volume fluctuations. These fluctuations often have been unrelated to the operating performance of companies in these markets. Market fluctuations and broad market, economic, and industry factors may negatively affect the price of our Class A Common Stock, regardless of our operating performance. Any volatility or a significant decrease in the market price of our Class A Common Stock could also negatively affect our ability to make acquisitions using Class A Common Stock. Further, if we were to be the object of securities class action litigation as a result of volatility in our Class A Common Stock price or for other reasons, it could result in substantial costs and diversion of our management’s attention and resources, which could negatively affect our financial results.
## We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and our stock price may be negatively affected.
As of December 31, 2018, we are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”). Section 404 requires that we document and test our internal control over financial reporting and issue our management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm issue an attestation report on such internal control. If we fail to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, or if we or our auditors identify and report material weaknesses in our internal control over financial reporting, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our Class A Common Stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.
## Anti-takeover provisions could make a third-party acquisition difficult.
Our Third Amended and Restated Certificate of Incorporation provides for a classified board of directors, with each member serving a three-year term. Provisions in our Third Amended and Restated Certificate of Incorporation could make it more difficult for a third party to acquire us without the approval of our Board. In addition, the Delaware corporate statutes also contain certain provisions that could make an acquisition by a third party more difficult.
## Our stockholders may act by unilateral written consent.
Under our Third Amended and Restated Certificate of Incorporation, any action required to be taken at any annual or special meeting of our stockholders, or any action which may be taken at any annual or special meeting of such stockholders, may be taken without a meeting, without prior notice and without a vote, if a consent in writing, setting forth the action so taken, is signed by the holders of outstanding stock having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted. Thus, consents of this type can be effected without the participation or input of minority stockholders.
## Item 1B. Unresolved Staff Comments
None.
## Item 2. Properties
## Summary of Oil and Gas Properties
## Midland Basin
We have an operated position of approximately 22,800 net acres in the core of the Midland Basin of west Texas across Reagan, Upton, and Midland counties with an average working interest of approximately 94%. As of December 31, 2018, we had 15 gross vertical and 51 gross horizontal operated producing wells. Current internal estimates indicate 500 potential gross, largely de-risked, operated drilling locations, the vast majority of which are in various benches of the Wolfcamp and the Spraberry formations. Of these 500 operated locations, 462 locations are expected to have an average working interest of 83%, whereas 38 locations are expected to be operated units where we hold an average working interest of approximately 35%. We are actively pursuing trades
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and acquisitions of additional acreage that may increase our working interest in these 38 locations as well as increase our operated acreage.
We also have a non-operated position of approximately 6,700 net acres in the Midland Basin of west Texas, located in Howard, Glasscock, Martin and Midland counties, Texas. As of December 31, 2018, we had an interest in 100 gross vertical and 26 gross horizontal non-operated producing wells with an average working interest of approximately 36%.
We have identified 366 potential gross horizontal non-operated drilling locations in various benches of the Wolfcamp and Spraberry formations with an estimated average working interest of approximately 25%.
## Eagle Ford Trend
As of December 31, 2018, we held approximately 29,000 gross (14,100 net) operated leasehold acres in Fayette, Gonzales and Karnes counties, Texas. The acreage is located in the crude oil window of the Eagle Ford shale trend of south Texas and is prospective for the Eagle Ford, Austin Chalk and Upper Eagle Ford formations. We serve as the operator with working interests ranging from approximately 17% to 67%.
As of December 31, 2018, we operated 93 gross Eagle Ford wells and 13 gross Austin Chalk wells and had non-operated interests in approximately five gross producing Eagle Ford wells and one gross producing Austin Chalk well. We have identified a total of 68 potential gross Eagle Ford drilling locations in this acreage. In addition, because our acreage position is prospective for the Austin Chalk and Upper Eagle Ford formations, we may have additional future economic locations. The majority of our acreage is covered by an approximately 173 square mile 3-D seismic survey.
## Oil and Natural Gas Reserves
As of December 31, 2018, all of our oil and natural gas reserves were located in the state of Texas. We expect to further develop these properties through additional drilling and completion operations. Our reserve estimates have been prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), an independent petroleum engineering firm. The scope and results of CG&A’s procedures are summarized in a letter which is included as an exhibit to this report. For further information on estimated reserves, including information on estimated future net cash flows and the standardized measure of discounted future net cash flows, please refer to the Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) in Part II, Item 8 of the Notes to Consolidated Financial Statements of this report.
As of December 31, 2018, our estimated proved reserves totaled 98,847 MBOE and had a PV-10 value of approximately $1,008.5 million (see Non- GAAP Reconciliation below) and a Standardized Measure of Discounted Future Net Cash Flows of approximately $959.5 million, all of which relate to our properties in Texas. We incurred approximately $153.2 million in capital expenditures, primarily drilling and completion costs, during 2018. We expect to further develop our properties through additional drilling.
## 2018 Activity in Proved Reserves
From January 1, 2018 to December 31, 2018, our total estimated proved reserves increased 24% from 79,976 MBOE to 98,847 MBOE. Of that, estimated proved developed reserves increased 18% from 19,961 MBOE to 23,646 MBOE and estimated proved undeveloped reserves increased 25% from 60,015 MBOE to 75,201 MBOE. These increases are primarily attributable to our successful drilling efforts in the Midland Basin, acquisitions and trades during the year, as well as improved commodity prices.
## Proved Reserves as of December 31, 2018
The below table sets forth a summary of our estimated crude oil, natural gas and natural gas liquids reserves as of December 31, 2018, based on the annual reserve estimate prepared by CG&A. In preparing this reserve report, CG&A evaluated 100% of our properties at December 31, 2018. Proved reserves are estimated based on the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12- month period for the year. All prices and costs associated with operating wells were held constant in accordance with the SEC guidelines.
Our proved reserve categories as of December 31, 2018 are summarized in the table below:
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<img src='content_image/1049523.jpg'>
(1) Includes 32.6 MMBbl of oil, 62.6 Bcf of natural gas and 11.6 MMBbl of NGLs reserves attributable to noncontrolling interests. Additionally, $557.4 million of PV-10 and $530.2 million of standardized measure of discounted future net cash flows were attributable to noncontrolling interests.
(2) Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (BOE).
## Non-GAAP Reconciliation
PV-10 is a non-GAAP measure that differs from a measure under GAAP known as “standardized measure of discounted future net cash flows” in that PV-10 is calculated without including future income taxes. Management believes that the presentation of the PV-10 value of its oil and natural gas properties is relevant and useful to investors because it presents the estimated discounted future net cash flows attributable to our estimated proved reserves independent of our income tax attributes, thereby isolating the intrinsic value of the estimated future cash flows attributable to our reserves. We believe the use of a pre-tax measure provides greater comparability of assets when evaluating companies because the timing and quantification of future income taxes is dependent on company-specific factors, many of which are difficult to determine. For these reasons, management uses and believes that the industry generally uses the PV-10 measure in evaluating and comparing acquisition candidates and assessing the potential rate of return on investments in oil and natural gas properties. PV-10 does not necessarily represent the fair market value of oil and natural gas properties. PV-10 is not a measure of financial or operational performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.
The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows ( in thousands ):
<img src='content_image/1049524.jpg'>
(1) Includes $557.4 million attributable to noncontrolling interests.
(2) Includes $530.2 million attributable to noncontrolling interests.
## Drilled But Uncompleted Wells
In order to achieve efficiencies from a pricing and logistics standpoint, our customary sequence of drilling and completion operations is to drill a group of wells and defer completion operations until all drilling operations for the group are concluded and then commence completion activities. See activities related to wells included in our proved developed reserves subsequent to December 31, 2018 below.
<img src='content_image/1049525.jpg'>
## Reserve Quantity Information
The following table illustrates our estimated net proved reserves, including changes, and proved developed and proved undeveloped reserves for the periods indicated. The oil prices as of December 31, 2018 and 2017, are based on the respective 12-month
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unweighted average of the first of the month prices of the WTI spot prices which equates to $65.56 per barrel and $51.34 per barrel, respectively. The natural gas prices as of December 31, 2018 and 2017 are based on the respective 12-month unweighted average of the first of month prices of the Henry Hub spot price which equates to $3.10 per MMBtu and $2.98 per MMBtu, respectively. The natural gas liquids prices used to value reserves as of December 31, 2018 and 2017 averaged $28.81 per barrel and $22.59 per barrel, respectively. All prices are adjusted by lease or field for energy content, transportation fees, and market differentials. All prices are held constant in accordance with SEC guidelines.
A summary of our changes in quantities of proved oil, natural gas and NGLs reserves for the years ended December 31, 2018 and 2017 are as follows:
<img src='content_image/1058459.jpg'>
<img src='content_image/1058460.jpg'>
<img src='content_image/1058461.jpg'>
Notable changes in proved reserves for the year ended December 31, 2018 included the following:
• Extensions and discoveries. In 2018, total extensions and discoveries of 16.2 MMBOE was a result of successful drilling results and well performance primarily related to the Midland Basin.
• Sales of minerals in place. Sales of minerals in place totaled 6.6 MMBOE during 2018, which consisted of 4.7 MMBOE resulting from the disposition of non-operated properties in the Midland Basin as part of an acreage trade and 1.9 MMBOE related to the disposition of non-operated Eagle Ford properties, both further described in Note 3. Acquisitions and Divestitures in the Notes to Consolidated Financial Statements.
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## GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry and within this report.
3-D seismic – An advanced technology method of detecting accumulation of hydrocarbons identified through a three-dimensional picture of the subsurface created by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.
Bbl – One barrel or 42 U.S. gallons liquid volume of oil or other liquid hydrocarbons.
BOE – Barrel of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent. The ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas differs significantly from the price for a barrel of oil. A barrel of NGLs also differs significantly in price from a barrel of oil.
Btu – British thermal unit, the quantity of heat required to raise the temperature of one pound of water by one-degree Fahrenheit.
Completion – The process of treating and hydraulically fracturing a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate regulatory agency.
Developed acreage – The number of acres which are allotted or assignable to producing wells or wells capable of production.
Development activities – Activities following exploration including the drilling and completion of additional wells and the installation of production facilities.
Development well – A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole or well – A well found to be incapable of producing hydrocarbons economically.
Exploitation – A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
Exploratory well – A well drilled to find and produce oil or natural gas reserves in an area or a potential reservoir not classified as proved.
Farm-in or Farm-out – An agreement whereby the owner of a working interest in an oil and natural gas lease assigns or contractually conveys, subject to future assignment, the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the farmee is required to drill one or more wells in order to earn its interest in the acreage. The farmor usually retains a royalty and/or an after-payout interest in the lease. The interest received by the farmee is a “farm-in” while the interest transferred by the farmor is a “farm-out.”
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.
Gross acres or gross wells – The total acres or wells, as the case may be, in which a working interest is owned.
HBP – Held by production, a mineral lease provision that extends the right to operate and maintain a lease as long as the property produces a minimum quantity of oil and/or natural gas.
Horizontal drilling – A drilling technique that permits the operator to drill horizontally within a specified targeted reservoir and thus exposes a larger portion of the producing horizon to a wellbore than would otherwise be exposed through conventional vertical drilling techniques.
Hydraulic fracture or Frac – A well stimulation method by which fluid, comprised largely of water and proppant (purposely sized particles used to hold open an induced fracture) is injected downhole and into the producing formation at high pressures and rates in order to exceed the rock strength and create a fracture such that the proppant material can be placed into the fracture to enhance the productive capability of the formation.
Injection well – A well which is used to inject gas, water, or liquefied petroleum gas under high pressure into a producing formation to maintain sufficient pressure to produce the recoverable reserves.
Joint Development Agreement or JDA – An agreement that provides for the joint development of a tract of land typically utilized after the leasing phase has concluded or when minerals are HBP.
Joint Operating Agreement or JOA – Any agreement between working interest owners concerning the duties and responsibilities of the operator and rights and obligations of the non-operators.
MBbls – One thousand barrels of crude oil or other liquid hydrocarbons.
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## Estimated Costs Related to Conversion of Proved Undeveloped Reserves to Proved Developed Reserves
<img src='content_image/1043278.jpg'>
(1) Beginning in 2019 and thereafter, the production and cash flows represent the drilling results from the respective year plus the incremental effects from the results of proved undeveloped drilling from previous years. These production volumes, inflows, expenses, development costs and cash flows are limited to the PUD reserves and do not include any production or cash flows from the Proved Developed category which will also help to fund our capital program.
(2) Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (BOE).
(3) Computation is based on SEC pricing of (i) $61.18 per Bbl (WTI-Cushing spot prices, adjusted for differentials) and (ii) $2.13 per Mcf (Henry Hub spot natural gas price), as adjusted for location and quality by property.
Historically, our drilling programs have been substantially funded from our cash flow and borrowings under our credit facility. Based on current commodity prices and our current expectations over the next five years of our cash flows and drilling programs, which includes drilling of proved undeveloped and unproven locations, we believe that we can continue to substantially fund our drilling activities from our cash flow and with borrowings under the EEH Credit Agreement. In addition, historically, we have been able to take advantage of the capital markets, as needed, when opportunities arose.
## Preparation of Reserve Estimates
We engaged an independent petroleum engineering consulting firm, CG&A, to prepare our annual reserve estimates and we have relied on CG&A’s expertise to ensure that our reserve estimates are prepared in compliance with SEC guidelines.
The technical person primarily responsible for the preparation of the reserve report is Mr. W. Todd Brooker, President of CG&A. He graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering. Mr. Brooker is a Registered Professional Engineer in the State of Texas (License No. 83462) and has more than 25 years of experience in the estimation and evaluation of oil and natural gas reserves. He is also a member of the Society of Petroleum Engineers.
Robert J. Anderson, our President, is responsible for reservoir engineering, is a qualified reserve estimator and auditor and is primarily responsible for overseeing CG&A during the preparation of our annual reserve estimates. His professional qualifications meet or exceed the qualifications of reserve estimators and auditors set forth in the “Standards Pertaining to Estimation and Auditing of Oil and Natural Gas Reserves Information” promulgated by the Society of Petroleum Engineers. His qualifications include a Bachelor of Science degree in Petroleum Engineering from the University of Wyoming in 1986; a Master of Business Administration degree from the University of Denver in 1988; member of the Society of Petroleum Engineers since 1985; and more than 32 years of practical experience in estimating and evaluating reserve information with more than fifteen of those years being in charge of estimating and evaluating reserves.
We maintain adequate and effective internal controls over our reserve estimation process as well as the underlying data upon which reserve estimates are based. The primary inputs to the reserve estimation process are technical information, financial data, ownership interest and production data. The relevant field and reservoir technical information, which is updated, at least, annually, is assessed for validity when CG&A has technical meetings with our engineers, geologists, operations and land personnel. Current revenue and expense information is obtained from our accounting records, which are subject to external quarterly reviews, annual audits and our own set of internal controls over financial reporting. Internal controls over financial reporting are assessed for effectiveness annually using criteria set forth in Internal Control – Integrated Framework , (2013 Version) issued by the Committee of Sponsoring Organizations of the Treadway Commission. All current financial data such as commodity prices, lease operating expenses,
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## Item 4. Mine Safety Disclosures
Not applicable.
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2017 to $59.40 or 23% for the year ended December 31, 2018. We had a net increase in the volume of oil sold of 542 MBbls or 30%, primarily due to the Bold properties acquired on May 9, 2017 representing a partial prior year, partially offset by the impact of non-core asset divestitures that took place in the third and fourth quarters of 2017.
## Natural gas revenues
For the year ended December 31, 2018, natural gas revenues decreased by $1.4 million or 16% relative to the comparable period in 2017. Of the decrease, approximately $2.1 million was attributable to a decrease in our realized price, partially offset by an increase of $0.7 million attributable to increased volume. Our average realized price per Mcf decreased from $2.69 for the year ended December 31, 2017 to $2.05 or 24% for the year ended December 31, 2018. The total volume of natural gas produced and sold increased 350 MMcf or 11% primarily due to increased production at our Midland Basin properties as well as the impact of the timing of the Bold Transaction, partially offset by the impact of non-core asset divestitures that took place in the third and fourth quarters of 2017.
## Natural gas liquids revenues
For the year ended December 31, 2018, natural gas liquids revenues increased by $6.4 million or 60% relative to the comparable period in 2017. Of the increase, approximately $2.3 million was attributable to an increase in our realized price and $4.1 million was attributable to increased volume. The volume of natural gas liquids produced and sold increased by 155 MBbls or 31%, primarily due to the timing of the Bold Transaction which substantially increased our Midland Basin properties on May 9, 2017, partially offset by the impact of non-core asset divestitures that took place in the third and fourth quarters of 2017.
## Lease operating expense (“LOE”)
LOE includes all costs incurred to operate wells and related facilities for both operated and non-operated properties. In addition to direct operating costs such as labor, repairs and maintenance, re-engineering and workovers, equipment rentals, materials and supplies, fuel and chemicals, LOE includes product marketing and transportation fees, insurance, ad valorem taxes and overhead charges provided for in operating agreements.
LOE increased by $0.9 million or 4% for the year ended December 31, 2018 relative to the comparable period in 2017. The increase in LOE was due to a $1.9 million increase related to the Bold properties acquired on May 9, 2017 representing a partial prior year and a $4.4 million increase related to the increased number of producing wells resulting from our 2018 drilling program, offset by a $5.4 million decrease related to non-core asset divestitures that took place in the third and fourth quarters of 2017.
## Severance taxes
Severance taxes for the year ended December 31, 2018 increased by $2.0 million or 33% relative to the comparable period in 2017, primarily due to the increased prices of oil and natural gas liquids, partially offset by the impact of non-core asset divestitures that took place in the third and fourth quarters of 2017. However, as a percentage of revenues from oil, natural gas, and natural gas liquids, severance taxes remained flat when compared to the prior year period.
## Impairment
During the year ended December 31, 2018, we recorded non-cash asset impairments of $4.6 million to our unproved oil and natural gas properties resulting from certain acreage expirations related to our Eagle Ford Trend properties. During the year ended December 31, 2017, we recognized $72.2 million of non-cash asset impairments as a result of significant forward commodity price declines and the recording of certain acreage expirations that negatively impacted our results of operations and equity. These impairments consisted of $63.1 million to our proved oil and natural gas properties and $9.1 million to our unproved oil and natural gas properties, primarily to our properties located in the Eagle Ford Trend. See Note 7. Oil and Natural Gas Properties in the Notes to Consolidated Financial Statements for a discussion of how impairments are measured.
## Depreciation, depletion and amortization (“DD&A”)
DD&A increased for the year ended December 31, 2018 by $10.7 million, or 29% relative to the comparable period in 2017, due to the addition of the assets acquired in the Bold Transaction to the depletable base, as well as increased production volumes, partially offset by the impact of non- core asset divestitures that took place in the third and fourth quarters of 2017.
## General and administrative expense (“G&A”)
These expenses consist primarily of employee remuneration, professional and consulting fees and other overhead expenses. G&A increased by $1.1 million for the year ended December 31, 2018 relative to the comparable period in 2017, primarily due to the
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increase to 65 full-time employees from the prior year-end amount of 58, as well as additional employee bonus amounts resulting from the improved commodity price environment.
## Transaction costs
For the year ended December 31, 2018, transactions costs consisted of $13.5 million, primarily associated with the proposed Sabalo Acquisition terminated in December 2018. During the year ended December 31, 2017, we recorded $4.7 million in transaction costs primarily associated with the Bold Transaction completed in May 2017. See Note 3. Acquisitions and Divestitures in the Notes to Consolidated Financial Statements.
## Interest expense, net
Interest expense includes commitment fees, amortization of deferred financing costs, and interest on outstanding indebtedness. Interest expense for the year ended December 31, 2018 was $2.9 million compared to $2.7 million for the comparable period in 2017. The $0.2 million increase in interest expense was primarily due to higher average borrowings outstanding compared to the prior year period. See Note 13. Long-Term Debt in the Notes to Consolidated Financial Statements.
## Gain on sale of oil and gas properties, net
During the year ended December 31, 2018, we sold certain non-core oil and gas properties including our non-operated Eagle Ford assets located in south Texas, recording gains totaling $1.9 million. During the year ended December 31, 2017, we sold all of our oil and natural gas leases, oil and natural gas wells and associated assets located in the Williston Basin in North Dakota. We also sold certain of our non-core oil and natural gas properties in Texas, Montana, Oklahoma and North Dakota. In connection with these sales, we recorded gains totaling $9.1 million. See Note 3. Acquisitions and Divestitures in the Notes to Consolidated Financial Statements.
## Gain (loss) on derivative contracts, net
For the year ended December 31, 2018, we recorded a net gain on derivative contracts of $60.9 million, consisting of unrealized mark-to-market gains of $76.0 million, partially offset by net realized losses on settlements of $15.1 million. For the year ended December 31, 2017, we recorded a net loss on derivative contracts of $8.0 million, consisting of unrealized mark-to-market losses of $7.3 million and net realized losses on settlements of $0.7 million.
## Litigation Settlement
For the year ended December 31, 2018, we recorded an expense of $4.7 million related to the settlement of certain litigation. See Note 16. Commitments and Contingencies in the Notes to Consolidated Financial Statements.
## Income tax (expense) benefit
During the year ended December 31, 2018, we recorded total income tax expense of $2.5 million which included (1) deferred income tax expense for Lynden US of $1.9 million as a result of its share of the distributable income from EEH, offset by a $0.5 million discrete income tax benefit related to refundable AMT tax credits resulting from the TCJA, (2) deferred income tax expense for Earthstone of $7.4 million as a result of its share of the distributable income from EEH, which was used to reduce the valuation allowance recorded against its deferred tax asset as future realization of the net deferred tax asset cannot be assured and (3) deferred income tax expense of $1.1 million related to the Texas Margin Tax. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the year ended December 31, 2018.
During the year ended December 31, 2017, we recorded a total income tax benefit of $16.4 million which included (1) income tax benefit of $8.6 million, of which $4.8 million related to the reduction of that amount in its deferred tax liability resulting from the federal corporate income tax rate reduction to 21%, (2) a $7.7 million income tax benefit for Earthstone as a discrete item during the current reporting period, which resulted from a change in assessment of the realization of its net deferred tax assets due to the deferred tax liability that was recorded with respect to its investment in EEH as part of the Bold Transaction as an adjustment to Additional paid-in capital in the Consolidated Statement of Equity, and (3) income tax expense of $12.6 million related to the reduction of the amount in its deferred tax asset resulting from the federal corporate income tax rate reduction to 21% which was fully offset by the reduction in its valuation allowance for that amount because the future realization of such loss cannot be reasonably assured and is subject to a full valuation allowance. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the year ended December 31, 2017.
## Liquidity and Capital Resources
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We have significant undeveloped acreage and future drilling locations. Drilling horizontal wells, generally consisting of 7,500 to 12,000-foot lateral lengths, in the Midland Basin is capital intensive. At December 31, 2018, we had approximately $0.4 million in cash and approximately $196.2 million in unused borrowing capacity under the EEH Credit Agreement (discussed below) for a total of approximately $196.5 million in funds available for operational and capital funding. We currently estimate 2019 capital expenditures will be approximately $190 million, which assumes a 16-well program running one rig for our operated acreage in the Midland Basin and a seven-well program for our operated Eagle Ford acreage as well as estimated expenditures for our non-operated Midland Basin properties and land and infrastructure activities. We likely will continue to outspend our cash flows provided by operating activities over at least the next 12 months from the date of this report based on current assumptions. However, we believe we will have sufficient liquidity with cash flows from operations and borrowings under the EEH Credit Agreement for the next 12 months in order to meet our cash requirements. We may consider various financial arrangements or other techniques or transactions, including but not limited to promoted drilling arrangements.
Working Capital, defined as Total current assets less Total current liabilities as set forth in our Consolidated Balance Sheets, was a deficit of $18.3 million as of December 31, 2018 compared to a deficit of $21.8 million as of December 31, 2017. We used $150.0 million to fund our capital program, in addition to $32.6 million to acquire additional oil and natural gas properties, offset by $6.0 in cash proceeds from the disposition of certain non-core oil and natural gas properties in the Eagle Ford Trend, that was facilitated by $102.4 million of net cash provided by our operating activities resulting from increased oil prices as well as increased production resulting from our 2018 drilling and development program, net borrowings of $53.8 million under the EEH Credit Agreement and a reduction of our cash on hand by $22.6 million. Due to the costs incurred related to our drilling program, we may incur additional working capital deficits in the future. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil and natural gas production will continue to be the largest variables affecting our working capital.
We expect to finance future acquisition and development activities through available working capital, cash flows from operating activities, borrowings under the EEH Credit Agreement and, various means of corporate and project financing, assuming we can effectively access debt and equity markets. In addition, as indicated above, we may continue to partially finance our drilling activities through the sale of participating rights to financial institutions or industry participants, and we could structure such arrangements on a promoted basis, whereby we may earn working interests in reserves and production greater than our proportionate share of capital costs.
## Capital Expenditures
We have set our 2019 capital budget, which assumes a one-rig operated program and non-operated activities as currently proposed by operators, for our acreage in the Midland Basin as well as a seven-well program on our operated Eagle Ford acreage. Our anticipated capital expenditures for 2019 are currently estimated at $190 million.
Our accrual basis capital expenditures for the years ended December 31, 2018 and 2017 were as follows:
<img src='content_image/1057725.jpg'>
In addition to the capital expenditures described above, on October 5, 2018, we closed the Exchange. Under the terms of the Exchange, we acquired 3,899 net operated acres in Reagan County with virtually a 100% working interest, including producing assets representing a net production increase of approximately 350 Boe/d, in exchange for 1,222 net non-operated acres in Glasscock County with an average working interest of 39% and $27.8 million in cash, plus customary closing adjustments.
For further discussion, see Note 3. Acquisitions and Divestitures to the Notes to Consolidated Financial Statements included in this report.
## Credit Agreement
On November 6, 2018, in connection with a regularly scheduled borrowing base redetermination, the borrowing base under the EEH Credit Agreement was increased from $225.0 million to $275.0 million. As of December 31, 2018, we had $78.8 million of borrowings outstanding, bearing annual interest of 4.479%, resulting in a remaining $196.2 million of borrowing base available under the EEH Credit Agreement.
## Impairments to Oil and Natural Gas Properties
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future cash flows included in this report are prepared in accordance with guidelines established by the SEC and the Financial Accounting Standards Board (“FASB”). The accuracy of our reserve estimates is a function of:
• The quality and quantity of available data;
• The interpretation of that data;
• The accuracy of various mandated economic assumptions; and
• The judgments of the persons preparing the estimates.
Our proved reserves information included in this report is based on estimates prepared by our independent petroleum engineers, CG&A. The independent petroleum engineers evaluated 100% of our estimated proved reserve quantities and their related future net cash flows as of December 31, 2018. Estimates prepared by others may be higher or lower than our estimates. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. We make revisions to reserve estimates throughout the year as additional information becomes available. We make changes to depletion rates, impairment calculations, and asset retirement obligations in the same period that changes to reserve estimates are made.
## Depreciation, Depletion and Amortization
Our rate of recording DD&A is dependent upon our estimates of total proved and proved developed reserves, which estimates incorporate various assumptions and future projections. If the estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, reducing our net income. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. We are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploitation and development program, as well as future economic conditions.
## Impairment of Oil and Natural Gas Properties
We review the value of our oil and natural gas properties whenever management judges that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments of producing properties are determined by comparing the pretax future net undiscounted cash flows to the net book value at the end of each period. If the net capitalized cost exceeds undiscounted future cash flows, the cost of the property is written down to “fair value,” which is determined based on expected future cash flows using discount rates commensurate with the risks involved, using prices and costs consistent with those used for internal decision making. Different pricing assumptions or discount rates could result in a different calculated impairment. We provide for impairments on significant undeveloped properties when we determine that the property will not be developed or a permanent impairment in value has occurred.
## Asset Retirement Obligation
Our asset retirement obligations (“AROs”) consist primarily of estimated future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage, and land restoration in accordance with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. The recognition of an ARO requires that management make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; inflation rates; and future advances in technology. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the field.
## Derivative Instruments and Hedging Activity
We are exposed to certain risks relating to our ongoing business operations, such as commodity price risk. Derivative contracts are utilized to economically hedge our exposure to price fluctuations and reduce the variability in our cash flows associated with anticipated sales of future oil and natural gas production. We follow FASB ASC Topic 815, Derivatives and Hedging, to account for our derivative financial instruments. We do not enter into derivative contracts for speculative trading purposes. It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive. We did not post collateral under any of these contracts.
Our crude oil and natural gas derivative positions consist of swaps. Swaps are designed so that we receive or make payments based on a differential between fixed and variable prices for crude oil and natural gas. We have elected to not designate any of our derivative contracts for hedge accounting. Accordingly, we record the net change in the mark-to-market valuation of these derivative
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arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Proved undeveloped reserves or PUD – Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are schedule to be drilled within five years unless specific circumstances justify a longer time. Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Recompletion – The completion for production of an existing well bore in another formation from that in which the well has been previously completed.
Re-engineering – A process involving a comprehensive review of the mechanical conditions associated with wells and equipment in producing fields. Our re-engineering practices typically result in a capital expenditure plan which is implemented over time to workover (see below) and re- complete wells and modify down hole artificial lift equipment and surface equipment and facilities. The programs are designed specifically for individual fields to increase and maintain production, reduce down-time and mechanical failures, lower per-unit operating expenses, and therefore, improve field economics.
Reservoir – A permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Royalty interest – An interest in an oil and natural gas property entitling the owner to a share of oil or natural gas production free of costs of production.
SEC – United States Securities and Exchange Commission.
Shut-in reserves – Those reserves expected to be recovered from completion intervals that were open at the time the reserve was estimated but were not producing due to market conditions, mechanical difficulties or because production equipment or pipelines were not yet installed. These reserves are included in the PDNP category in our reserve report.
Slickwater – A method of hydraulic fracturing that predominately uses water and chemicals, with sand, that is injected into an oil or natural gas reservoir to create a fracture in the reservoir rock and create or enhance fluid flow.
Standardized Measure - The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue.
Undeveloped acreage – Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Working interest or WI – The ownership interest, generally defined in a JOA, that gives the owner the right to drill, produce and/or conduct operating activities on the property and share in the sale of production, subject to all royalties, overriding royalties and other burdens and obligates the owner of the interest to share in all costs of exploration, development operations and all risks in connection therewith.
Workover – Operations on a producing well to restore or increase production.
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March 12, 2019
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## Item 9B. Other Information
None.
## PART III
## Item 10. Directors, Executive Officers and Corporate Governance
See list of “Executive Officers of the Company” under Item 1 of this report, which is incorporated herein by reference.
The other information required by this item is incorporated herein by reference to the 2019 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2018.
## Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the 2019 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2018.
## Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this item is incorporated herein by reference to the 2019 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2018.
## Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated herein by reference to the 2019 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2018.
## Item 14. Principal Accounting Fees and Services
The information required by this item is incorporated herein by reference to the 2019 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2018.
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## Item 1. Business
## Overview
## PART I
Earthstone Energy, Inc., a Delaware corporation (“Earthstone” and together with our consolidated subsidiaries, the “Company,” “our,” “we,” “us,” or similar terms), is a growth-oriented independent oil and gas company engaged in the acquisition and development of oil and gas reserves through activities that include the acquisition, drilling and development of undeveloped leases, asset and corporate acquisitions and mergers. Our operations are all in the upstream segment of the oil and natural gas industry and all our properties are onshore in the United States. At present, our primary assets are located in the Midland Basin of west Texas and the Eagle Ford Trend of south Texas.
Our primary focus is concentrated in the Midland Basin of west Texas, a high oil and liquids rich resource basin which provides us with multiple horizontal targets with proven production results, long-lived reserves and historically high drilling success rates. During 2018, we used one drilling rig and successfully drilled 16 wells in the Midland Basin with an average working interest of 89%. We completed 19 Midland Basin wells during 2018, including three wells that came online at the end of December 2018. With 866 potential gross horizontal drilling locations in the Midland Basin, we are focused on developmental drilling and completion operations in the area. We currently plan to maintain a one-rig drilling program on our operated acreage in the Midland Basin and expect to drill approximately 16 wells in 2019. Additionally, we continue to pursue acreage trades in the southern Midland Basin with the intent of increasing our operated acreage and drilling inventory, drilling and completing longer laterals and realizing greater operating efficiency.
We also own certain assets in the Eagle Ford Trend of south Texas where we have locations in the Eagle Ford and Austin Chalk formations. During 2018, we drilled five Eagle Ford wells with an average working interest of 17% and completed 11 wells (five wells with a 17% working interest and six wells with a 25% working interest). We expect to drill seven wells, with an average working interest of 22%, in this area during 2019 and may consider additional drilling based on improvements in oil and natural gas commodity prices. We have 67 potential gross operated drilling locations in the Eagle Ford Trend for future development.
We have approximately 29,500 net acres in the core of the Midland Basin, of which 77% is operated and 23% is non-operated. Upon finalization of documents for an agreed-upon mineral lease in Reagan County, which is expected to occur in the first quarter of 2019, we will have approximately 30,200 net acres in the core of the Midland Basin. We hold an approximate 94% working interest in our operated acreage and an approximate 40% working interest in our non-operated acreage. Our operated acreage in the Midland Basin is primarily located in Reagan, Upton and Midland counties. Our non-operated acreage in the Midland Basin is located primarily in Howard, Glasscock, Martin, Midland and Reagan counties. In total, we have an interest in 192 gross producing wells in the Midland Basin. We have approximately 14,300 net leasehold acres in the Eagle Ford Trend, which primarily consists of approximately 14,100 operated net leasehold acres in the crude oil window in Fayette, Gonzales and Karnes counties, with working interests ranging from approximately 17% to 67%. We have an interest in 106 gross operated producing wells and six gross non- operated producing wells in the Eagle Ford Trend.
At December 31, 2018, our estimated proved oil and natural gas reserves were approximately 98,847 MBOE based on the reserve report prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), our independent petroleum engineers. Based on this report, at December 31, 2018, our proved reserve quantities were approximately 60% oil, 19% natural gas, 21% NGLs with 24% of those reserves classified as proved developed. The calculated percentages include proved developed non-producing reserves. Of these interests, approximately 54,628 MBOE are attributable to noncontrolling interests. See Note 9. Noncontrolling Interest in the Notes to Consolidated Financial Statements.
## Our Business Strategy
Our current business strategy is to focus on the economic development of our existing acreage, increase our acreage and horizontal well locations in the Midland Basin and increase stockholder value through the following:
• pursue value-accretive acquisition and corporate merger opportunities, which could increase the scale of our operations;
• profitably increase cash flows, production and reserves by selectively developing our acreage base;
• expand our acreage positions and drilling inventory in our areas of primary interest through acquisitions and farm-in opportunities, with an emphasis on operated positions;
• block up acreage to allow for 10,000-foot (or longer) horizontal lateral drilling locations which provide higher economic returns;
• maintain operating control over the majority of our production, development and undeveloped acreage; and
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## $^{ }$Note 1. – Organization and Basis of Presentation
## EARTHSTONE ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Earthstone Energy, Inc., a Delaware corporation (“Earthstone” and together with its consolidated subsidiaries, the “Company”), is a growth- oriented independent oil and natural gas development and production company. In addition, the Company is active in corporate mergers and the acquisition of oil and natural gas properties that have production and future development opportunities. The Company’s operations are all in the up-stream segment of the oil and natural gas industry and all its properties are onshore in the United States.
Earthstone is the sole managing member of Earthstone Energy Holdings, LLC, a Delaware limited liability company (together with its wholly-owned consolidated subsidiaries, “EEH”), with a controlling interest in EEH. Earthstone, together with its wholly-owned subsidiary, Lynden Energy Corp., a corporation organized under the laws of British Columbia (“Lynden Corp”), and Lynden Corp’s wholly-owned consolidated subsidiary, Lynden USA Inc., a Utah corporation (“Lynden US”) and also a member of EEH, consolidates the financial results of EEH and records a noncontrolling interest in the Consolidated Financial Statements representing the economic interests of EEH's members other than Earthstone and Lynden US.
Certain prior period amounts have been reclassified to conform to current period presentation within the Consolidated Financial Statements. Prior period Re-engineering and workovers in the Consolidated Statements of Operations have been reclassified from its own line item and included in Lease operating expenses, within Operating Costs and Expenses, to conform to current period presentation. Additionally, prior-period Stock-based compensation in the Consolidated Statements of Operations has been reclassified from its own line item and included in General and administrative expense, within Operating Costs and Expenses, to conform to current-period presentation. These reclassifications had no effect on Income (loss) from operations or any other subtotal in the Consolidated Statements of Operations.
## Bold Contribution Agreement
On May 9, 2017, Earthstone completed a contribution agreement dated as of November 7, 2016 and as amended on March 21, 2017 (the “Bold Contribution Agreement”), by and among Earthstone, EEH, Lynden US, Lynden USA Operating, LLC, a Texas limited liability company (“Lynden Op”), Bold Energy Holdings, LLC, a Texas limited liability company (“Bold Holdings”), and Bold Energy III LLC, a Texas limited liability company (“Bold”). The purpose of the Bold Contribution Agreement was to provide for, among other things described below, the business combination between Earthstone and Bold, which owned significant developed and undeveloped oil and natural gas properties in the Midland Basin of Texas (the “Bold Transaction”).
The Bold Transaction was structured in a manner commonly known as an “Up-C.” Under this structure and the Bold Contribution Agreement, (i) Earthstone recapitalized its common stock into two classes – Class A common stock, $0.001 par value per share (the “Class A Common Stock”), and Class B common stock, $0.001 par value per share (the “Class B Common Stock”), and all of Earthstone’s existing outstanding common stock, $0.001 par value per share (the “Common Stock”), was recapitalized on a one-for-one basis for Class A Common Stock (the “Recapitalization”); (ii) Earthstone transferred all of its membership interests in Earthstone Operating, LLC, Sabine River Energy, LLC, EF Non-Op, LLC and Earthstone Legacy Properties, LLC (formerly Earthstone GP, LLC) and $36,071 in cash from the sale of Class B Common Stock to Bold Holdings (collectively, the “Earthstone Assets”) to EEH, in exchange for 16,791,296 membership units of EEH (the “EEH Units”); (iii) Lynden US transferred all of its membership interests in Lynden Op to EEH in exchange for 5,865,328 EEH Units; (iv) Bold Holdings transferred all of its membership interests in Bold to EEH in exchange for 36,070,828 EEH Units and purchased 36,070,828 shares of Class B Common Stock issued by Earthstone for $36,071; and (v) Earthstone granted an aggregate of 150,000 fully vested shares of Class A Common Stock under Earthstone’s 2014 Long-Term Incentive Plan, as amended (the “2014 Plan”), to certain employees of Bold. Each EEH Unit, together with one share of Class B Common Stock, are convertible into one share of Class A Common Stock.
The Bold Transaction was recorded in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 805, Business Combinations, and is consolidated in these financial statements in accordance with FASB ASC Topic 810, Consolidation, which requires the recording of a noncontrolling interest component of net income (loss), as well as a noncontrolling interest component within equity, including changes to additional paid-in capital to reflect the noncontrolling interest within equity in the Consolidated Balance Sheet as of December 31, 2018 at the noncontrolling interest’s respective membership interest in EEH.
## Note 2. – Summary of Significant Accounting Policies
## Principles of Consolidation
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## NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
## EARTHSTONE ENERGY, INC.
Noncontrolling Interest represents third-party equity ownership of EEH and is presented as a component of equity in the Consolidated Balance Sheet as of December 31, 2018 and 2017, as well as an adjustment to Net income in the Consolidated Statement of Operations for the years ended December 31, 2018 and 2017. As of December 31, 2018, Earthstone and Lynden US owned a 44.7% membership interest in EEH while Bold Holdings, the noncontrolling third party, owned the remaining 55.3%. See further discussion in Note 9. Noncontrolling Interest .
## Segment Reporting
Operating segments are components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance.
Based on our organization and management, we have only one reportable operating segment, which is oil and natural gas exploration and production.
## Comprehensive Income
The Company has no elements of comprehensive income other than net income.
## Asset Retirement Obligations
Asset retirement obligations associated with the retirement of long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the asset, including the asset retirement cost, is depreciated over the useful life of the asset. Asset retirement obligations are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of asset retirement obligations change, an adjustment is recorded to both the asset retirement obligations and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. For further discussion, see Note 14. Asset Retirement Obligations .
## Business Combinations
The Company accounts for its acquisitions of oil and gas properties not commonly controlled in accordance with FASB ASC Topic 805, Business Combinations, which, among other things, requires the Company to determine if an asset or a business has been acquired. If the Company determines an asset(s) has been acquired, the asset(s) acquired, as well as any liabilities assumed, are measured and recorded at the acquisition date cost. If the Company determines a business has been acquired, the assets acquired and liabilities assumed are measured and recorded at their fair values as of the acquisition date, recording goodwill for amounts paid in excess of fair value.
## Revenue Recognition
Revenues for the sale of oil, natural gas and natural gas liquids are recognized when the recognition criteria of ASC 606 “Revenue from Contracts with Customers,” are met, which generally occurs as the product is delivered to customers’ custody transfer points and collectability is reasonably assured. The Company fulfills its performance obligations under its customer contracts through daily delivery of oil, natural gas and natural gas liquids and revenues are recorded on a monthly basis and the Company receives payment from one to three months after delivery. The prices received for oil, natural gas and natural gas liquids sales under the Company's contracts are generally derived from stated market prices which are then adjusted to reflect deductions including transportation, fractionation and processing. As a result, revenues from the sale of oil, natural gas and natural gas liquids will decrease if market prices decline. The sales of oil, natural gas and natural gas liquids as presented on the Consolidated Statements of Operations represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling oil, natural gas and natural gas liquids on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. The Company follows the sales method of accounting for gas imbalances. The Company had no significant gas imbalances as of December 31, 2018 or 2017.
## Concentration of Credit Risk
Credit risk represents the actual or perceived financial loss that the Company would record if its purchasers, operators, or counterparties failed to perform pursuant to contractual terms.
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• maintain a strong balance sheet and financial flexibility.
## Our Strengths
We believe that the following strengths will be beneficial in achieving our business goals:
• extensive horizontal development potential in one of the most oil rich basins of the United States;
• experienced management team with substantial technical and operational expertise and a history of successful acquisition and merger transactions;
• operating control over the majority of our production and development activities; and
• conservative balance sheet.
## Recent Developments
## Terminated Contribution Agreement
As previously disclosed in our Current Report on Form 8-K filed on October 17, 2018 with the SEC, on October 17, 2018, Earthstone, Earthstone Energy Holdings, LLC (“EEH”) and Sabalo Holdings, LLC (“Sabalo Holdings”) entered into a contribution agreement (the “Contribution Agreement”) which provided for the contribution by Sabalo Holdings of all its interests in Sabalo Energy, LLC (“Sabalo Energy”) and Sabalo Energy, Inc. to EEH (the “Sabalo Acquisition”). On December 21, 2018, Earthstone, EEH and Sabalo Holdings entered into a termination agreement (the “Termination Agreement”), pursuant to which the parties mutually terminated the Contribution Agreement.
In connection with the Termination Agreement, Earthstone, EEH and Sabalo Holdings also agreed to release each other from certain claims and liabilities arising out of or related to the Contribution Agreement and the transactions contemplated therein or thereby. In addition, we estimated total transaction costs to be approximately $13.4 million, including payment to Sabalo Holdings of $1.6 million for reimbursement of its expenses. All other related agreements were also terminated in conjunction with the termination of the Contribution Agreement.
## Midland Basin Acreage Trade
On October 5, 2018, we closed a transaction in the Midland Basin that included producing properties and undeveloped acreage (the "Exchange"). Under the terms of the Exchange, we acquired 3,899 net operated acres in Reagan County with virtually a 100% working interest, in exchange for 1,222 net non-operated acres in Glasscock County with an average working interest of 39% and $27.8 million in cash, subject to customary closing adjustments. The effective date of the transaction was September 1, 2018.
Along with the net increase of 2,677 acres, the Exchange also resulted in a net production increase of approximately 350 Boe/d. The producing wells acquired in the Exchange are connected into a third-party crude oil pipeline gathering system, which will assure flow capacity for this production as well as any volumes from future wells on this acreage. With these acreage acquisitions, our total net acreage in the Midland Basin increased to approximately 29,500 acres, of which approximately 22,800 acres are operated by us. For further discussion, see Note 3. Acquisitions and Divestitures in the Notes to Consolidated Financial Statements included in this report. Upon finalization of documents for an agreed-upon mineral lease in Reagan County, which is expected to occur in the first quarter of 2019, we will have approximately 30,200 net acres in the core of the Midland Basin.
## Bold Transaction
On May 9, 2017, Earthstone completed a contribution agreement dated as of November 7, 2016 and as amended on March 21, 2017 (the “Bold Contribution Agreement”), by and among Earthstone, EEH, Lynden USA Inc., a Utah corporation ("Lynden US"), Lynden USA Operating, LLC, a Texas limited liability company (“Lynden Op”), Bold Energy Holdings, LLC, a Texas limited liability company (“Bold Holdings”), and Bold Energy III LLC, a Texas limited liability company (“Bold”). The purpose of the Bold Contribution Agreement was to provide for, among other things described below, the business combination between Earthstone and Bold, which owned significant developed and undeveloped oil and natural gas properties in the Midland Basin of Texas (the “Bold Transaction”).
The Bold Transaction was structured in a manner commonly known as an “Up-C.” Under this structure and the Bold Contribution Agreement, (i) Earthstone recapitalized its common stock into two classes - Class A common stock, $0.001 par value per share (the “Class A Common Stock”), and Class B common stock, $0.001 par value per share (the “Class B Common Stock”), and all of Earthstone’s existing outstanding common stock, $0.001 par value per share (the “Common Stock”), was recapitalized on a
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## NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
## EARTHSTONE ENERGY, INC.
anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. The Company’s acquisitions are discussed in Note 3. Acquisitions and Divestitures .
## Asset Retirement Obligations
The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. The significant inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, well life, inflation and credit-adjusted risk-free rate. See Note 14. Asset Retirement Obligations for a reconciliation of the beginning and ending balances of the liability for the Company’s asset retirement obligations.
## Note 6. Derivative Financial Instruments
The Company’s hedging activities consist of derivative instruments entered into in order to hedge against changes in oil and natural gas prices through the use of fixed price swaps and basis swaps agreements. Swaps exchange floating price risk in the future for a fixed price at the time of the hedge. Consistent with its hedging policy, the Company has entered into a series of derivative instruments to hedge a significant portion of its expected oil and natural gas production through December 31, 2020. Typically, these derivative instruments require payments to (receipts from) counterparties based on specific indices as required by the derivative agreements. Although not risk free, the Company believes these instruments reduce its exposure to oil and natural gas price fluctuations and, thereby, allow the Company to achieve a more predictable cash flow.
The Company’s derivative instruments are cash flow hedge transactions in which it is hedging the variability of cash flow related to a forecasted transaction. The Company does not enter into derivative instruments for trading or other speculative purposes. These transactions are recorded in the Consolidated Financial Statements in accordance with FASB ASC Topic 815. The Company has accounted for these transactions using the mark-to-market accounting method. Generally, the Company incurs accounting losses on derivatives during periods where prices are rising and gains during periods where prices are falling which may cause significant fluctuations in the Consolidated Balance Sheets and Consolidated Statements of Operations.
The Company nets its derivative instrument fair value amounts executed with each counterparty pursuant to an International Swap Dealers Association Master Agreement (“ISDA”), which provides for net settlement over the term of the contract. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.
The following table sets forth the Company’s outstanding derivative contracts at December 31, 2018. When aggregating multiple contracts, the weighted average contract price is disclosed.
<img src='content_image/1043810.jpg'>
(1) The basis differential price is between LLS Argus Crude and the WTI NYMEX.
(2) The basis differential price is between WTI Midland Argus Crude and the WTI NYMEX.
(3) The basis differential price is between W. Texas (WAHA) and the Henry Hub NYMEX.
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gas properties are based on (i) proved reserves, (ii) forward commodity prices and assumptions as to costs and expenses, and (iii) the estimated discount rate that would be used by potential purchasers to determine the fair value of the assets.
## Unproved Oil and Natural Gas Properties
Unproved properties consist of costs incurred to acquire undeveloped leases as well as the cost to acquire unproved reserves. Undeveloped lease costs and unproved reserve acquisition costs are capitalized. Unproved oil and natural gas leases are generally for a primary term of three to five years. In most cases, the term of the unproved leases can be extended by paying delay rentals, meeting contractual drilling obligations, or by the presence of producing wells on the leases. Unproved costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units-of-production basis.
The Company reviews its unproved properties periodically for impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current exploration and development plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease term for the property.
The Company had the following non-cash asset impairment charges to its oil and natural gas properties for the years ended December 31, 2018 and 2017 ( in thousands ):
<img src='content_image/1041097.jpg'>
Accumulated impairments to proved and unproved oil and natural gas properties as of December 31, 2018 and 2017 were $121.1 million and $148.2 million, respectively.
## Note 8. Goodwill
Goodwill represents the excess of the purchase price of assets acquired over the fair value of those assets and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. Such test includes an assessment of qualitative and quantitative factors.
The Company did not have any non-cash impairment charges to its goodwill for the years ended December 31, 2018 or 2017.
Accumulated impairments to Goodwill as of December 31, 2018 and 2017 were $19.1 million.
## Note 9. Noncontrolling Interest
As a result of the Bold Transaction, Earthstone became the sole managing member of, and has a controlling interest in, EEH. As the sole managing member of EEH, Earthstone operates and controls all of the business and affairs of EEH and its subsidiaries. Immediately following the Bold Transaction, Earthstone and Lynden US owned a 38.6% membership interest in EEH while Bold Holdings owned the remaining 61.4%.
The Bold Transaction was recorded in accordance with FASB ASC Topic 805, Business Combinations, and is consolidated in these financial statements in accordance with FASB ASC Topic 810, Consolidation, which requires the recording of a noncontrolling interest component of net income (loss), as well as a noncontrolling interest component within equity, including changes to Additional paid-in capital to reflect the noncontrolling interest within equity in the Consolidated Balance Sheet as of December 31, 2017 at the noncontrolling interest’s respective membership interest in EEH. A reconciliation of the equity attributable to the noncontrolling interest as of May 9, 2017 is as follows ( in thousands ):
<img src='content_image/1041096.jpg'>
(1) See Note 3. Acquisitions and Divestitures .
(2) Represents 61.4% of total equity attributable to EEH as of May 9, 2017.
Earthstone consolidates the financial results of EEH and its subsidiaries, and records a noncontrolling interest for the economic interest in Earthstone held by the members of EEH other than Earthstone and Lynden US. Net loss attributable to noncontrolling
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## NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
## EARTHSTONE ENERGY, INC.
On May 9, 2017, and in connection with the completion of the Bold Transaction, Earthstone recapitalized its Common Stock into two classes, as described in Note 1. Organization and Basis of Presentation , Class A Common Stock and Class B Common Stock. At that time, all of Earthstone’s existing outstanding Common Stock was automatically converted on a one-for-one basis into Class A Common Stock.
## Class A Common Stock
At December 31, 2018 and 2017, there were 28,696,321 and 27,584,638 shares of Class A Common Stock issued and outstanding, respectively. During the years ended December 31, 2018 and 2017, as a result of the vesting and settlement of restricted stock units under the 2014 Plan, Earthstone issued 681,585 and 703,214 shares of Class A Common Stock, respectively, of which 169,893 and 61,055 shares of Class A Common Stock, respectively, were retained as treasury stock and canceled to satisfy the related employee income tax liability. On July 1, 2017, Earthstone retired and returned the 15,357 shares of treasury stock to authorized but unissued shares of Class A Common Stock. Additionally, on May 9, 2017, under the Bold Contribution Agreement, Earthstone issued 150,000 shares of Class A Common Stock valued at approximately $2.0 million on that date. For additional information, see Note 3. Acquisitions and Divestitures .
## Class A Common Stock Offering
In October 2017, Earthstone completed a public offering of 4,500,000 shares of Class A Common Stock, at an issue price of $9.25 per share. Earthstone received net proceeds from this offering of $39.4 million, after deducting underwriters’ fees and offering expenses of $2.2 million. The net proceeds from the offering were used to repay outstanding indebtedness under the EEH Credit Agreement, as described in Note 13. Long-Term Debt .
## Class B Common Stock
At December 31, 2018 and 2017, there were 35,452,178 and 36,052,169 shares of Class B Common Stock issued and outstanding, respectively. Each share of Class B Common Stock, together with one EEH Unit, is convertible into one share of Class A Common Stock. During the years ended December 31, 2018 and 2017, 599,991 and 18,659 shares, respectively, of Class B Common Stock and EEH Units were exchanged for an equal number of shares of Class A Common Stock. On May 9, 2017, in connection with Earthstone’s completion of the Bold Transaction, Earthstone issued 36,070,828 shares of Class B Common Stock in exchange for $36 thousand. For additional information, see Note 3. Acquisitions and Divestitures .
## Note 12. Stock-Based Compensation
## Restricted Stock Units
The 2014 Plan allows, among other things, for the grant of restricted stock units (“RSUs”). On June 6, 2018, at the annual meeting of stockholders, Earthstone's stockholders approved an amendment and restatement of the 2014 Plan, including increasing the shares of Class A Common Stock that may be issued under the Plan by 600,000 shares, to a total of 6.4 million shares.
Each RSU represents the contingent right to receive one share of Class A Common Stock. The holders of outstanding RSUs do not receive dividends or have voting rights prior to vesting and settlement. Prior to May 9, 2017, the Company determined the fair value of granted RSUs based on the market price of the Common Stock on the date of the grant. Beginning on May 9, 2017, the Company began determining the fair value of granted RSUs based on the market price of the Class A Common Stock on the date of the grant. Compensation expense for granted RSUs is recognized on a straight-line basis over the vesting term and is net of forfeitures, as incurred. Stock-based compensation is included in General and administrative expense in the Consolidated Statements of Operations and is recorded with a corresponding increase in Additional paid-in capital within the Consolidated Balance Sheet.
The table below summarizes unvested RSU activity for the year ended December 31, 2018:
<img src='content_image/1038531.jpg'>
During the year ended December 31, 2018, Earthstone granted 561,000 RSUs to employees and 6,500 RSUs to certain members of the Board with vesting periods ranging from 12 to 36 months. The total grant date fair value of the RSUs granted during the
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$0.5 million of remaining unamortized deferred financing costs were expensed and included in Write-off of deferred financing costs in the Consolidated Statements of Operations.
On May 9, 2017, EEH (the “Borrower”), Earthstone Operating, LLC, EF Non-Op, LLC, Sabine River Energy, LLC, Earthstone Legacy Properties, LLC, Lynden Op, Bold, Bold Operating, LLC (the “Guarantors”), BOKF, NA dba Bank Of Texas, as Agent and Lead Arranger, Wells Fargo Bank, National Association as Syndication Agent and the lenders party thereto (the “Lenders”), entered into a credit agreement (the “EEH Credit Agreement”).
The borrowing base under the EEH Credit Agreement is subject to redetermination on or about November 1st and May 1st of each year. The amounts borrowed under the EEH Credit Agreement bear annual interest rates at either (a) the London Interbank Offered Rate (“LIBOR”) plus 1.75% to 2.75% or (b) the prime lending rate of Bank of Texas plus 0.75% to 1.75%, depending on the amounts borrowed under the EEH Credit Agreement. Principal amounts outstanding under the EEH Credit Agreement are due and payable in full at maturity on May 9, 2022. All of the obligations under the EEH Credit Agreement, and the guarantees of those obligations, are secured by substantially all of EEH’s assets. Additional payments due under the EEH Credit Agreement include paying a commitment fee of 0.375% or 0.50%, depending on borrowing base utilization, per year to the Lenders in respect of the unutilized commitments thereunder, as well as certain other customary fees.
The EEH Credit Agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, EEH’s ability to incur additional indebtedness, create liens on assets, make investments, enter into sale and leaseback transactions, pay dividends and make distributions or repurchase its limited liability interests, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable and engage in certain transactions with affiliates.
In addition, the EEH Credit Agreement requires EEH to maintain the following financial covenants: a current ratio, as defined, of not less than 1.0 to 1.0 and a leverage ratio of not greater than 4.0 to 1.0. Leverage ratio means the ratio of (i) the aggregate debt of EEH and its consolidated subsidiaries as at the last day of the fiscal quarter (excluding any debt from obligations relating to non-cash losses under FASB ASC 815 as a result of changes in the fair market value of derivatives) to (ii) the product of EBITDAX for such fiscal quarter multiplied by four. The term “EBITDAX” means, for any period, the sum of consolidated net income for such period plus (a) the following expenses or charges to the extent deducted from consolidated net income in such period: (i) interest, (ii) taxes, (iii) depreciation, (iv) depletion, (v) amortization, (vi) non-cash losses under FASB ASC 815 as a result of changes in the fair market value of derivatives, (vii) exploration expenses, (viii) impairment expenses, and (ix) non-cash compensation expenses and minus (b) to the extent included in consolidated net income in such period, non-cash gains under FASB ASC 815 as a result of changes in the fair market value of derivatives.
The EEH Credit Agreement contains customary affirmative covenants and defines events of default to include failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default, and if Frank A. Lodzinski ceases to serve and function as Chief Executive Officer of EEH and the majority of the Lenders do not approve of Mr. Lodzinski’s successor. Upon the occurrence and continuance of an event of default, the Lenders have the right to accelerate repayment of the loans and exercise their remedies with respect to the collateral. As of December 31, 2018, EEH was in compliance with the covenants under the EEH Credit Agreement.
As of December 31, 2018, the Company had a $275.0 million borrowing base under the EEH Credit Agreement, of which $78.8 million was outstanding, bearing annual interest of 4.479%, resulting in an additional $196.2 million of borrowing base availability under the EEH Credit Agreement. At December 31, 2017, there were $25.0 million of borrowings outstanding under the EEH Credit Agreement.
For the year ended December 31, 2018, the Company had borrowings of $156.8 million and $103.0 million in repayments of borrowings.
For the years ended December 31, 2018 and 2017, interest on all outstanding debt averaged 4.16% and 4.26% per annum, respectively, of which excluded commitment fees of $0.8 million and $0.3 million for each period ended, respectively, and amortization of deferred financing costs of $0.3 million for each period ended, respectively.
The Company capitalized $0.5 million and $1.4 million, respectively, of costs associated with the credit agreements for the years ended December 31, 2018 and 2017. These capitalized costs are included in Other noncurrent assets in the Consolidated Balance Sheets. The Company’s policy is to capitalize the financing costs associated with its debt and amortize those costs on a straight-line basis over the term of the associated debt.
## Note 14. Asset Retirement Obligations
The Company has asset retirement obligations associated with the future plugging and abandonment of oil and natural gas properties and related facilities. Revisions to the liability typically occur due to changes in the estimated abandonment costs, well economic lives, and the discount rate.
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one-for-one basis for Class A Common Stock (the “Recapitalization”); (ii) Earthstone transferred all of its membership interests in Earthstone Operating, LLC, Sabine River Energy, LLC, EF Non-Op, LLC and Earthstone Legacy Properties, LLC (formerly Earthstone GP, LLC) and $36,071 in cash from the sale of Class B Common Stock to Bold Holdings (collectively, the “Earthstone Assets”) to EEH, in exchange for 16,791,296 membership units of EEH (the “EEH Units”); (iii) Lynden US transferred all of its membership interests in Lynden Op to EEH in exchange for 5,865,328 EEH Units; (iv) Bold Holdings transferred all of its membership interests in Bold to EEH in exchange for 36,070,828 EEH Units and purchased 36,070,828 shares of Class B Common Stock issued by Earthstone for $36,071; and (v) Earthstone granted an aggregate of 150,000 fully vested shares of Class A Common Stock under Earthstone’s 2014 Long-Term Incentive Plan, as amended (the “2014 Plan”), to certain employees of Bold. Each EEH Unit, together with one share of Class B Common Stock, are convertible into one share of Class A Common Stock.
## Organizational Structure
Earthstone is the sole managing member of EEH, with a controlling interest in EEH. Earthstone, together with its wholly-owned subsidiary, Lynden Energy Corp., a corporation organized under the laws of British Columbia (“Lynden Corp”), and Lynden Corp’s wholly-owned consolidated subsidiary, Lynden US and also a member of EEH, consolidates the financial results of EEH and records a noncontrolling interest in the Consolidated Financial Statements representing the economic interests of EEH's members other than Earthstone and Lynden US.
## Our Operations
We are currently the operator of properties containing approximately 82% of our proved oil and natural gas reserves and 86% of our proved PV-10 as of December 31, 2018 (see reconciliation of PV-10 to the standardized measure of discounted future net cash flows in Item 2. Properties). As operator, we manage and are able to directly influence development and production of operations of our operated properties. Independent contractors engaged by us provide all the equipment and personnel associated with drilling and completion activities. We employ petroleum engineers, geologists and land professionals who work on improving operating cost, production rates and reserves. Our producing properties have reasonably predictable production profiles and cash flows, subject to commodity price fluctuations. Our status as an operator has allowed us to pursue the development of undeveloped acreage, further develop existing properties and generate new projects.
As is common in our industry, we selectively participate in drilling and developmental activities in non-operated properties. Decisions to participate in non-operated properties are dependent upon the technical and economic nature of the projects and the operating expertise and financial standing of the operators.
## Operational Risks
Oil and natural gas exploitation, development and production involve a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that we will acquire, discover or produce additional oil and natural gas in commercial quantities. Oil and natural gas operations also involve the risk that well fires, blowouts, equipment failure, human error and other events may cause accidental leakage or spills of toxic or hazardous materials, such as petroleum liquids or drilling fluids into the environment or cause significant injury to persons or property. In such event, substantial liabilities to third parties or governmental entities may be incurred, the satisfaction of which could substantially reduce our available cash and possibly result in loss of oil and natural gas properties. Such hazards may also cause damage to or destruction of wells, producing formations, production facilities and pipeline or other processing facilities.
As is common in the oil and natural gas industry, we do not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a material effect on our operating results, financial position and cash flows. For further discussion of these risks see Item 1A. Risk Factors of this report.
## Marketing and Customers
We market the majority of the production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our production to purchasers at market prices.
We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business. For the year ended December 31, 2018, three purchasers accounted for 27%, 11% and 10%, respectively, of our revenue during the period. For the year ended December 31, 2017, three purchasers accounted for 18%, 14% and 14%, respectively, of our revenue during the period. No other customer accounted for more than 10% of our revenue during these periods. If a major customer decided to stop purchasing oil and natural gas from us, revenue could decline and our operating results and financial condition could be harmed. However, we believe that the loss of any one or all of our major purchasers would not have a materially adverse effect on our financial condition or results of operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.
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<img src='content_image/1056253.jpg'>
For further information about our significant Fiscal 2021, Fiscal 2020, and Fiscal 2019 transactions, refer to (i) MD&A and (ii) Notes 2 and 10.
## Business segments
We have four reportable segments: (i) Beer, (ii) Wine and Spirits, (iii) Corporate Operations and Other, and (iv) Canopy. The business segments reflect how our operations are managed, resources are allocated, operating performance is evaluated by senior management, and the structure of our internal financial reporting. Our ownership interest in Canopy allows us to exercise significant influence, but not control, and, therefore, we account for our investment in Canopy under the equity method. Amo unts included below for the Canopy segment represent 100% of Canopy’s reported results on a two-month lag, prepared in accordance with U.S. GAAP , and converted from Canadian dollars to U.S. dollars. Although we own less than 100% of the outstanding shares of Canopy, 100% of the Canopy results are included in the information below and subsequently eliminated to reconcile to our consolidated financ ial statements . We report net sales in two reportable segments, as Canopy is eliminated in consolidation, as follows:
<img src='content_image/1056252.jpg'>
<img src='content_image/1056256.jpg'>
<img src='content_image/1056257.jpg'>
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## Lease maturities (1)
As of February 28, 2021, minimum payments due for lease liabilities for each of the five succeeding fiscal years and thereafter are as follows:
<img src='content_image/1052125.jpg'>
For leases with terms in excess of 12 months at inception. (1)
## Supplemental information
<img src='content_image/1052126.jpg'>
<img src='content_image/1052127.jpg'>
Our leases have varying terms with remaining lease terms of up to approximately 30 years. Certain of our lease arrangements provide us with the option to extend or to terminate the lease early. (1)
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The fair value of shares vested for our restricted Class A Common Stock awards is as follows:
<img src='content_image/1023654.jpg'>
The weighted average grant-date fair value of performance share units granted with a market condition and the weighted average inputs used to estimate the fair value on the date of grant using the Monte Carlo Simulation model are as follows:
<img src='content_image/1023653.jpg'>
Based primarily on historical volatility levels of our Class A Common Stock. (1)
Based on the implied yield currently available on U.S. Treasury zero coupon issues with a remaining term equal to the performance period. (2)
No expected dividend yield as units granted earn dividend equivalents. (3)
## Employee Stock Purchase Plan
We have an Employee Stock Purchase Plan under which 9,000,000 shares of Class A Common Stock may be issued. Under the terms of the plan, eligible employees may purchase shares of our Class A Common Stock through payroll deductions. The purchase price is the lower of 85% of the fair market value of the stock on the first or last day of the purchase period. For the years ended February 28, 2021, February 29, 2020, and February 28, 2019, employees purchased 67,801 shares, 69,324 shares, and 76,844 shares, respectively, under this plan.
## Other
As of February 28, 2021, there was $66.8 million of total unrecognized compensation cost related to nonvested stock-based compensation arrangements granted under our stock-based employee compensation plans. This cost is expected to be recognized in our results of operations over a weighted-average period of 2.1 years. With respect to the issuance of shares under any of our stock- based compensation plans, we have the option to issue authorized but unissued shares or treasury shares.
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## 23. SUBSEQUENT EVENT
## Mexicali Brewery
In April 2021, our Board of Directors authorized management to sell or abandon the Mexicali Brewery. Subsequently, management determined that we will be unable to use or repurpose certain assets at the Mexicali Brewery. Accordingly, in the first quarter of fiscal 2022, we expect to recognize a long-lived asset impairment of approximately $650 million to $680 million which will be included within our consolidated results of operations. The fair value will be determined based on the expected salvage value of the abandoned assets as of April 2021. We are continuing to work with government officials in Mexico to (i) determine next steps for our suspended Mexicali Brewery construction project and (ii) pursue various forms of recovery for capitalized costs and additional expenses incurred in establishing the brewery, however, there can be no assurance of any recoveries. In the medium-term, under normal operating conditions, we have ample capacity at the Nava and Obregon breweries to meet consumer needs based on current growth forecasts and current and planned production capabilities. To align with our anticipated future growth expectations we are also working with the Mexican government to explore options to add further capacity at another location in Southeastern Mexico where there is ample water and a skilled workforce to meet our long-term needs.
## 24. SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
A summary of selected quarterly financial information is as follows:
<img src='content_image/1028015.jpg'>
Includes the following: (1)
<img src='content_image/1028016.jpg'>
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31.2 Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith).
32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 (filed herewith).
32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 (filed herewith).
99.1 Constellation Brands, Inc. 1989 Employee Stock Purchase Plan (amended and restated as of July 24, 2013) (filed as Exhibit 99.1 to the Company’s Current Report on Form 8-K dated July 24, 2013, filed July 26, 2013 and incorporated herein by reference). *#
99.2 First Amendment, dated and effective April 25, 2016, to the Company’s 1989 Employee Stock Purchase Plan (filed as Exhibit 99.1 to the Company’s Current Report on Form 8-K dated April 25, 2016, filed April 28, 2016 and incorporated herein by reference). *#
99.3 Final Judgment filed with the United States District Court for the District of Columbia on October 24, 2013, together with Exhibits B and C (filed as Exhibit 99.1 to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended November 30, 2013 and incorporated herein by reference). #
99.4 Consent Agreement, dated April 18, 2019, by and between CBG Holdings LLC and Canopy Growth Corporation (incorporated herein by reference to Exhibit 99.4 of Canopy Growth Corporation’s Form 6-K filed April 30, 2019).
99.5 Second Amended and Restated Investor Rights Agreement, dated April 18, 2019, by and among Greenstar Canada Investment Limited Partnership, CBG Holdings LLC and Canopy Growth Corporation (incorporated herein by reference to Exhibit 99.3 of Canopy Growth Corporation’s Form 6-K filed April 30, 2019).
101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document (filed herewith).
101.SCH XBRL Taxonomy Extension Schema Document (filed herewith).
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith).
101.DEF XBRL Taxonomy Extension Definition Linkbase Document (filed herewith).
101.LAB XBRL Taxonomy Extension Labels Linkbase Document (filed herewith).
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith).
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
* Designates management contract or compensatory plan or arrangement.
# Company’s Commission File No. 001-08495. For filings prior to October 4, 1999, use Commission File No. 000-07570.
† The exhibits, disclosure schedules, and other schedules, as applicable, have been omitted pursuant to Item 601(a)(5) of Regulation S-K. Constellation Brands, Inc. agrees to furnish supplementally a copy of such exhibits, disclosure schedules, and other schedules, as applicable, or any section thereof, to the SEC upon request.
‡ Portions of this exhibit are redacted pursuant to Item 601(b)(2)(ii) of Regulation S-K.
+ Portions of this exhibit were redacted pursuant to a confidential treatment request filed with and approved by the Securities and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended.
We agree, upon request of the Securities and Exchange Commission, to furnish copies of each instrument that defines the rights of holders of long-term debt of the Company or its subsidiaries that is not filed herewith pursuant to Item 601(b)(4)(iii)(A) because the total amount of long-term debt authorized under such instrument does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis.
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Our Daleville facility, located in Roanoke, Virginia, supports our craft and specialty business in addition to our domestic innovation initiatives.
In the U.S., we operate 11 wineries using many varieties of grapes grown principally in the Napa, Sonoma, Monterey, and San Joaquin regions of California. We also operate two wineries in New Zealand and six wineries in Italy. Grapes are crushed in September through November in the U.S. and Italy, and in March through May in New Zealand and stored as wine until packaged for sale under our brand names or sold in bulk. The inventories of wine are usually at their highest levels during and after the crush of each year’s grape harvest and are reduced as sold throughout the year.
We currently operate four distilleries in the U.S. for the production of our spirits; two facilities for High West whiskey, one facility for Copper & Kings American brandies, and one facility for Nelson’s Green Brier bourbon and whiskey products. The requirements for grains and bulk spirits used in the production of our spirits are purchased from various suppliers.
Certain of our wines and spirits must be aged for multiple years. Therefore, our inventories of wines and spirits may be larger in relation to sales and total assets than in many other businesses.
## Resources and availability of production materials
The principal components in the production of our Mexican and craft beer brands include water; agricultural products, such as yeast and grains; and packaging materials, which include glass, aluminum, and cardboard.
For our Mexican beer brands, packaging materials represent the largest cost component of production, with glass bottles representing the largest cost component of our packaging materials.
For Fiscal 2021, the package format mix of our Mexican beer volume sold in the U.S. was as follows:
<img src='content_image/1024431.jpg'>
The Nava and Obregon breweries receive water originating from aquifers. We believe we have adequate access to water to support the breweries’ on-going requirements, as well as future requirements after the completion of planned expansion activities. Both breweries also take advantage of onsite wastewater treatment operations to reuse water consumed as part of the production process.
As part of our efforts to solidify our beer glass sourcing strategy over the long-term, we formed an equally-owned joint venture with Owens-Illinois, one of the leading manufacturers of glass containers in the world. The joint venture owns a state-of-the-art glass production plant adjacent to our Nava Brewery in Mexico. The glass plant currently has five operational glass furnaces which supply approximately 55% of the total annual glass bottle supply for our Mexican beer brands. We also have long-term glass supply agreements with other glass producers.
The principal components in the production of our wine and spirits products are agricultural products, such as grapes and grain, and packaging materials, primarily glass.
Most of our annual grape requirements are satisfied by grower purchases from each year’s harvest which normally begins in August and runs through October in the U.S. and Italy, and begins in February and runs through May in New Zealand. We receive grapes from approximately 180 independent growers in the U.S. and 55 independent growers located in New Zealand and Italy. We enter into purchase agreements with a majority of these growers with pricing that generally varies year-to-year and is largely based on then-current market prices.
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storm in Texas or Mexico, and climate change may negatively affect agricultural productivity in the regions from which we presently source our various agricultural raw materials or the energy supply powering our production facilities. Decreased availability of our raw materials may increase the cost of goods for our products. Severe weather events or changes in the frequency or intensity of weather events can also disrupt our supply chain, which may affect production operations, insurance cost and coverage, as well as delivery of our products to wholesalers, retailers, and consumers. Natural disasters such as severe storms, floods, and earthquakes may also negatively impact the ability of consumers to purchase our products.
We may experience significant future increases in the costs associated with environmental regulatory compliance, including fees, licenses, and the cost of capital improvements for our operating facilities to meet environmental regulatory requirements. In addition, we may be party to various environmental remediation obligations arising in the normal course of our business or relating to historical activities of businesses we acquire. Due to regulatory complexities, uncertainties inherent in litigation, and the risk of unidentified contaminants in our current and former properties, the potential exists for remediation, liability, and indemnification costs to differ materially from the costs that we have estimated. We may incur costs associated with environmental compliance arising from events we cannot control, such as unusually severe floods, hurricanes, earthquakes, or fires. We cannot assure that our costs in relation to these matters will not exceed our projections or otherwise have a material adverse effect upon our business, liquidity, financial condition, and/or results of operations.
## Reliance on wholesale distributors, major retailers, and government agencies
Local market structures and distribution channels vary worldwide. Within our primary market in the U.S., we offer a range of beverage alcohol products with generally separate distribution networks utilized for our beer portfolio and our wine and spirits portfolio. In the U.S., we sell our products principally to wholesalers for resale to retail outlets and directly to government agencies. We have an exclusive arrangement with one wholesaler that will generate a large portion of our U.S. wine and spirits net sales. Wholesalers and retailers of our products offer products which compete directly with our products for retail shelf space, promotional support and consumer purchases, and wholesalers or retailers may give higher priority to products of our competitors. The replacement or poor performance of our major wholesalers, retailers, or government agencies could result in temporary or longer- term sales disruptions or could have a material adverse effect on our business, liquidity, financial condition, and/or results of operations.
## Contamination and degradation of product quality from diseases, pests, and the effects of weather and climate conditions
Contamination, whether arising accidentally or through deliberate third-party action, or other events that harm the integrity or consumer support for our brands, could adversely affect sales. Various diseases, pests, fungi, viruses, drought, frosts, and certain other weather conditions or the effects of climate conditions, such as smoke taint from wildfires, could affect the quality and quantity of barley, hops, grapes, and other agricultural raw materials available, decreasing the supply and quality of our products. Similarly, power disruptions due to weather conditions could adversely impact our production processes and the quality of our products. We cannot guarantee that we and/or our suppliers of agricultural raw materials will succeed in preventing contamination in existing and/or future vineyards or fields. Future government restrictions regarding the use of certain materials used in growing grapes or other agricultural raw materials may increase vineyard costs and/or reduce production of grapes or other crops. It is also possible that a supplier may not provide materials or product components which meet our required standards or may falsify documentation associated with the fulfillment of those requirements.
Product contamination or tampering or the failure to maintain our standards for product quality, safety, and integrity, including with respect to raw materials, naturally occurring compounds, packaging materials, or product components obtained from suppliers, may also reduce demand for our products or cause production and delivery disruptions. Contaminants or other defects in raw materials, packaging materials, or product components purchased from third parties and used in the production of our beer, wine, or spirits products, or defects in the fermentation or distillation process could lead to low beverage quality as well as illness among, or injury to, consumers of our products and may result in reduced sales of the affected brand or all our brands.
If any of our products become unsafe or unfit for consumption, are misbranded, or cause injury, we may have to engage in a product recall and/or be subject to liability and incur additional costs. A widespread product
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## Item 2. Properties
We operate breweries, wineries, distilling plants, and bottling plants, many of which include warehousing and distribution facilities on the premises, and through a joint venture, we operate a glass production plant. In addition to our material properties described below, certain of our businesses maintain office space for sales and similar activities and offsite warehouse and distribution facilities in a variety of geographic locations.
Our corporate headquarters are located in leased offices in Victor, New York. Our segments also maintain leased office spaces in other locations in the U.S. and internationally.
We believe that our facilities, taken as a whole, are in good condition and working order. Within the Wine and Spirits segment, we have adequate capacity to meet our needs for the foreseeable future. Within the Beer segment, we have adequate capacity to meet our current needs and we have undertaken activities to increase our production capacity to address our anticipated future demand. As of February 28, 2021, our material properties by segment, all of which are owned, unless otherwise noted, consist of:
<img src='content_image/1042637.jpg'>
The glass production plant in Nava, Coahuila, Mexico is owned and operated by an equally-owned joint venture with Owens-Illinois and is located adjacent to our Nava Brewery. (1)
The distribution center in Lodi, California is a leased facility. (2)
Within our Wine and Spirits segment, as of February 28, 2021, we owned, leased, or had interests in approximately 10,100 acres of vineyards in California (U.S.), 6,800 acres of vineyards in New Zealand, and 1,300 acres of vineyards in Italy.
## Item 3. Legal Proceedings
For information regarding Legal Proceedings, see Risk Factors and Note 16.
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net cash proceeds were used for general corporate purposes. For the year ended February 28, 2021, we recognized a net gain of $58.9 million on the sale of the business.
## Wine and Spirits Divestitures
In January 2021, we sold a portion of our wine and spirits business, including lower-margin, lower-growth wine and spirits brands, related inventory, interests in certain contracts, wineries, vineyards, offices, and facilities. We received net cash proceeds of $538.4 million, subject to certain post-closing adjustments. In addition, we have the potential to earn an incremental $250 million of contingent consideration if certain brand performance targets are met over a two-year period after closing.
In January 2021, we also sold the New Zealand-based Nobilo Wine brand and certain related assets. We received cash proceeds of $129.0 million, subject to certain post-closing adjustments.
The cash proceeds from the Wine and Spirits Divestitures were utilized to repay the 3.75% May 2013 Senior Notes and for other general corporate purposes. For the year ended February 28, 2021, we recognized a net loss of $35.7 million on the Wine and Spirits Divestitures.
## Concentrate Business Divestiture
In December 2020, we sold certain brands used in our concentrates and high-color concentrate business, and certain intellectual property, inventory, goodwill, interests in certain contracts, and assets of our concentrates and high-color concentrate business.
The following presents selected financial information included in our historical consolidated financial statements that are no longer part of our consolidated results of operations following the Paul Masson Divestiture, Wine and Spirits Divestitures, and Concentrate Business Divestiture:
<img src='content_image/1058651.jpg'>
Included in selling, general, and administrative expenses within our consolidated results of operations. (1)
## Copper & Kings acquisition
In September 2020, we acquired the remaining ownership interest in Copper & Kings which primarily included the acquisition of inventories, and property, plant, and equipment. This acquisition included a collection of traditional and craft batch-distilled American brandies and other select spirits. The results of operations of Copper & Kings are reported in the Wine and Spirits segment and have been included in our consolidated results of operations from the date of acquisition.
## Empathy Wines acquisition
In June 2020, we acquired Empathy Wines, which primarily included the acquisition of goodwill, trademarks, and inventory. This acquisition, which included a digitally-native wine brand, strengthened our position in the direct-to-consumer and eCommerce markets. The results of operations of Empathy Wines are reported in the Wine and Spirits segment and have been included in our consolidated results of operations from the date of acquisition.
## Booker Vineyard investment
In April 2020, we invested in Booker Vineyard, a super-luxury, direct-to-consumer focused wine business that is accounted for under the equity method. We recognize our share of their equity in earnings (losses) in our consolidated financial statements in the Wine and Spirits segment.
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## I nventory step-up
In connection with acquisitions, the allocation of purchase price in excess of book value for certain inventories on hand at the date of acquisition is referred to as inventory step-up. Inventory step-up represents an assumed manufacturing profit attributable to the acquired business prior to acquisition.
## Accelerated depreciation
We recognized accelerated depreciation for certain assets primarily in connection with the multi-year implementation of a new global ERP system which is intended to replace our then-existing operating and financial systems.
## Undesignated commodity derivative contracts
Net gain (loss) on undesignated commodity derivative contracts represents a net gain (loss) from the changes in fair value of undesignated commodity derivative contracts. The net gain (loss) is reported outside of segment operating results until such time that the underlying exposure is recognized in the segment operating results. At settlement, the net gain (loss) from the changes in fair value of the undesignated commodity derivative contracts is reported in the appropriate operating segment, allowing the results of our operating segments to reflect the economic effects of the commodity derivative contracts without the resulting unrealized mark to fair value volatility.
## Selling, general, and administrative expenses
## Restructuring and other strategic business development costs
We recognized costs primarily in connection with costs to optimize our portfolio, gain efficiencies, and reduce our cost structure within the Wine and Spirits segment.
## Net gain (loss) on foreign currency derivative contracts
We recognized a net loss primarily in connection with the settlement of foreign currency forward contracts entered into to fix the U.S. dollar cost of the May 2020 Canopy Investment.
## Transaction, integration, and other acquisition-related costs
We recognized transaction, integration, and other acquisition-related costs in connection with our investments, acquisitions, and divestitures.
## Impairment of intangible assets
We recognized trademark impairment losses related to our Beer segment’s Four Corners craft beer trademark asset (Fiscal 2021) and Ballast Point craft beer trademark asset (Fiscal 2020). For additional information, refer to Note 7.
## COVID-19 incremental costs
We recognized costs for payments to third-party general contractors to maintain their workforce for expansion activities at the Obregon Brewery and recognized costs for incremental wages and hazard payments to employees.
## Other gains (losses)
We recognized other gains (losses) primarily in connection with (i) a gain recognized on the sale of a vineyard (Fiscal 2021), (ii) a gain on the remeasurement of our previously held equity interest in Nelson’s Green Brier to the acquisition-date fair value (Fiscal 2020), (iii) an increase in estimated fair value of a contingent liability associated with a prior period acquisition (Fiscal 2020), and (iv) recognition of previously deferred gain upon release of a related guarantee (Fiscal 2020).
## Impairment of assets held for sale
We recognized impairments of long-lived assets held for sale in connection with the (i) Wine and Spirits Divestitures (Fiscal 2021, Fiscal 2020), (ii) the Concentrate Business Divestiture (Fiscal 2021, Fiscal 2020), and (iii) the Ballast Point Divestiture (Fiscal 2020). For additional information, refer to Note 7.
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## Gain (loss) on sale of business
We recognized a net gain (loss) primarily on the completion of the Paul Masson Divestiture, the Wine and Spirits Divestitures (Fiscal 2021), and the Black Velvet Divestiture (Fiscal 2020).
## Income (loss) from unconsolidated investments
We recognized an unrealized gain (loss) primarily from (i) the changes in fair value of our securities measured at fair value, (ii) equity in earnings (losses) from Canopy’s results of operations, (iii) equity losses from Canopy related to costs designed to improve their organizational focus, streamline operations, and align production capability with projected demand (Fiscal 2021), and (iv) the increase in fair value resulting from the June 2019 modification of the terms of the November 2018 Canopy Warrants (Fiscal 2020). For additional information, refer to Notes 7 and 10.
## Business segments
<img src='content_image/1031338.jpg'>
Includes an adjustment to remove volume associated with the Ballast Point Divestiture for the period March 2, 2019, through February 29, 2020. (1)
Depletions represent distributor shipments of our respective branded products to retail customers, based on third-party data. (2)
The increase in Beer net sales is largely due to $451.6 million of volume growth within our Mexican beer portfolio, which benefited from continued consumer demand, new product introductions, and line extensions, $69.7 million favorable impact from pricing in select markets within our Mexican beer portfolio, and $35.0 million increase from favorable product mix shift, partially offset by $92.0 million from the Ballast Point Divestiture. Favorable product mix shift primarily resulted from increased sales of Corona Hard Seltzer and a reduction in on-premise keg sales. Inventory in our distribution channels returned to normal levels by the end of Fiscal 2021 following reduced production levels at our major breweries in Mexico earlier in the year.
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## Capital expenditures
During Fiscal 2021, we incurred $864.6 million for capital expenditures, including $693.9 million for the Beer segment primarily for the Mexico Beer Projects.
We plan to spend from $1.0 billion to $1.1 billion for capital expenditures in Fiscal 2022, including approximately $900 million for the Beer segment associated primarily with the Mexico Beer Projects. The remaining planned Fiscal 2022 capital expenditures consist of improvements to existing operating facilities and replacements of existing equipment and/or buildings. The Mexico Beer Projects are expected to be completed by Fiscal 2025. Accordingly, we expect to spend approximately $700 million to $900 million annually in Fiscal 2023 through Fiscal 2025 for the Beer segment. Management reviews the capital expenditure program periodically and modifies it as required to meet current business needs.
<img src='content_image/1033434.jpg'>
In fiscal 2017, we began construction of the Mexicali Brewery. In March 2020, a public consultation was held on the construction of our Mexicali Brewery. Following the negative result of the public consultation, we are in discussions with government officials in Mexico regarding next steps for our brewery construction project and options elsewhere in the country. We intend to continue working with government officials to mutually agree upon a path forward. At this time, we have suspended all Mexicali Brewery construction activities. See Note 23 for further discussion.
## Critical accounting policies and estimates
Our significant accounting policies are more fully described in Note 1. Certain policies are particularly important to the portrayal of our financial position and results of operations and require the application of significant judgment by management to determine appropriate assumptions to be used in certain estimates; as a result, they are subject to an inherent degree of uncertainty. Estimates are based on historical experience, observance of trends in the industry, information provided by our customers and information available from other outside sources, as appropriate. We review estimates to ensure that they appropriately reflect changes in our business on an ongoing basis. Our critical accounting estimates include:
• Fair value of financial instruments. Management’s estimate of fair value requires significant judgment and is subject to a high degree of variability based upon market conditions and the availability of specific information. The fair values of our financial instruments that require the application of significant judgment by management are as follows:
## Canopy investment
Equity securities, Warrants – estimated using the Black-Scholes option-pricing model (Level 2 fair value measurement) and Monte Carlo simulations (Level 2 fair value measurement). These valuation models use various market-based inputs, including stock price, remaining contractual term, expected volatility, risk-free interest rate, and expected dividend yield, as applicable. Management applies significant judgment in its determination of expected volatility. We consider both historical and implied volatility levels of the underlying equity security and apply limited consideration of historical peer group volatility levels.
Debt securities, Convertible – estimated using a binomial lattice option-pricing model (Level 2 fair value measurement), which includes an estimate of the credit spread based on market spreads using bond data as of the valuation date. This valuation model uses various market-based inputs,
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increased rate of revenue decline and increased competition, indicated that it was more likely than not the fair value of our indefinite-lived intangible asset associated with the Ballast Point craft beer trademarks might be below its carrying value. Accordingly, we performed a quantitative assessment for impairment. As a result of this assessment, the Ballast Point craft beer trademark asset recognized an impairment loss of $11.0 million. For the fourth quarter of fiscal 2019, the Beer segment’s Ballast Point business recognized a trademark impairment loss of $108.0 million in connection with certain continuing negative trends within its craft beer portfolio and a change in strategy for this portfolio focused on improving profitability by rationalizing the number of product offerings while targeting distribution growth in select strategic markets. Refer to Note 7 for further discussion.
The most significant assumptions used in the relief from royalty method to determine the estimated fair value of intangible assets with indefinite lives in connection with impairment testing are: (i) the estimated royalty rate, (ii) the discount rate, (iii) the expected long-term growth rate, and (iv) the annual revenue projections. As of January 1, 2021, if we used a royalty rate that was 50 basis points lower or used a discount rate that was 50 basis points higher or used an expected long-term growth rate that was 50 basis points lower or used annual revenue projections that were 100 basis points lower in our impairment testing of intangible assets with indefinite lives, then each change individually would not have resulted in any unit of accounting’s carrying value exceeding its estimated fair value.
Divestitures – When some, but not all of a reporting unit is disposed of, some of the goodwill of the reporting unit should be allocated to the portion of the reporting unit being disposed of, if that portion constitutes a business. The allocation of goodwill is based on the relative fair values of the portion of the reporting unit being disposed of and the portion of the reporting unit remaining. This approach requires a determination of the fair value of both the business being disposed and the businesses retained within the reporting unit.
For Fiscal 2021, o ur estimate of fair value for the Paul Masson Divestiture, the Wine and Spirits Divestitures, the Concentrate Business Divestiture, and the Ballast Point Divestiture was determined based on the expected proceeds from the transactions. The components sold were a part of the Wine and Spirits or Beer segment and were included in those reporting units through the date of divestiture. Goodwill was allocated to the assets held for sale based on the relative fair value of the businesses being sold compared to the relative fair value of the reporting unit. Goodwill not allocated to assets associated with the respective divestitures remained in the wine and spirits or beer reporting unit.
• Accounting for income taxes. We estimate our deferred tax assets and liabilities, income taxes payable, provision for income taxes, and unrecognized tax benefit liabilities based upon various factors including, but not limited to, historical pretax operating income, future estimates of pretax operating income, differences between book and tax treatment of various items of income and expense, interpretation of tax laws, and tax planning strategies. We are subject to income taxes in Canada, Mexico, Switzerland, the U.S., and other jurisdictions. We are regularly audited by federal, state, and foreign tax authorities, but a number of years may elapse before an uncertain tax position is audited and finally resolved.
We believe all tax positions are fully supported. We recognize tax assets and liabilities in accordance with the FASB guidance for income tax accounting. Accordingly, we recognize a tax benefit from an uncertain tax position when it is more likely than not the position will be sustained upon examination based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. Due to the complexity of some of these uncertainties, the ultimate resolution may result in a payment that is materially different from our current estimate of the unrecognized tax benefit liabilities. In addition, changes in existing tax laws or rates could significantly change our current estimate of our unrecognized tax benefit liabilities. These differences will be reflected as increases or
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decreases to income tax expense in the period in which they are determined. Changes in current estimates, if significant, could have a material adverse impact on our financial statements.
We recognize our deferred tax assets and liabilities based upon the expected future tax outcome of amounts recognized in our results of operations. If necessary, we recognize a valuation allowance on deferred tax assets when it is more likely than not they will not 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, historical, and projected operating results, and the availability of prudent and feasible tax planning strategies. The realization of deferred tax assets 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. We believe it is more likely than not the results of future operations will generate sufficient taxable income to realize our existing deferred tax assets, net of valuation allowances. Changes in the realizability of our deferred tax assets will be reflected in our effective tax rate in the period in which they are determined.
## Change in Accounting Guidance
Accounting guidance adopted for Fiscal 2021 did not have a material impact on our consolidated financial statements.
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## Management’s Annual Report on Internal Control Over Financial Reporting
Management of Constellation Brands, Inc. and subsidiaries (the “Company”) is responsible for establishing and maintaining an adequate system of internal control over financial reporting. This system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles.
The Company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time.
Management conducted an evaluation of the effectiveness of the system of internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of February 28, 2021.
The effectiveness of the Company’s internal control over financial reporting has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included herein.
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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Rochester, New York April 20, 2021
/s/ KPMG LLP
|
67,969
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https://cdla.io/permissive-1-0/
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To the Stockholders and Board of Directors Constellation Brands, Inc.:
## Opinion on the Consolidated Financial Statements
## Report of Independent Registered Public Accounting Firm
We have audited the accompanying consolidated balance sheets of Constellation Brands, Inc. and subsidiaries (the Company) as of February 28, 2021 and February 29, 2020, the related consolidated statements of comprehensive income (loss), changes in stockholders’ equity, and cash flows for each of the fiscal years in the three-year period ended February 28, 2021, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of February 28, 2021 and February 29, 2020, and the results of its operations and its cash flows for each of the fiscal years in the three-year period ended February 28, 2021, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of February 28, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated April 20, 2021 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting .
## Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
## Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
## Fair value measurement of the Canopy warrants
As discussed in Notes 1 and 7 to the consolidated financial statements, the Company established policies for measuring the fair value of financial instruments, including the November 2018 Canopy Warrants. As of February 28, 2021, the recorded balance of the Company’s investment in the November 2018 Canopy Warrants was $1,639.7 million. The Company uses option pricing models to estimate the fair value of the November 2018 Canopy Warrants using various market-based inputs.
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67,970
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https://cdla.io/permissive-1-0/
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duration of the aging process. All barreled whiskey and brandy are classified as in-process inventories and are included in current assets, in accordance with industry practice. Warehousing, insurance, value added taxes, and other carrying charges applicable to barreled whiskey and brandy held for aging are included in inventory costs.
We assess the valuation of our inventories and reduce the carrying value of those inventories that are obsolete or in excess of our forecasted usage to their estimated net realizable value based on analyses and assumptions including, but not limited to, historical usage, future demand, and market requirements.
## Property, plant, and equipment
Property, plant, and equipment is stated at cost. Major additions and improvements are recognized as an increase to the property accounts, while maintenance and repairs are expensed as incurred. The cost of properties sold or otherwise disposed of and the related accumulated depreciation are eliminated from the balance sheet accounts at the time of disposal and resulting gains and losses are included as a component of operating income.
Interest incurred relating to expansion, construction, and optimization of facilities is capitalized to construction in progress. We cease the capitalization of interest when construction activities are substantially completed and the facility and related assets are available for their intended use. At this point, construction in progress is transferred to the appropriate asset class.
## Depreciation
Depreciation is computed primarily using the straight-line method over the following estimated useful lives:
<img src='content_image/1036113.jpg'>
## Derivative instruments
We enter into derivative instruments to manage our exposure to fluctuations in foreign currency exchange rates, commodity prices, and interest rates. 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 all derivatives as either assets or liabilities and measure those instruments at estimated fair value (see Notes 6 and 7). We present our derivative positions gross on our balance sheets.
The change in the fair value of outstanding cash flow hedges is deferred in stockholders’ equity as a component of AOCI. For all periods presented herein, gains or losses deferred in stockholders’ equity as a component of AOCI are recognized in our results of operations in the same period in which the hedged items are recognized and on the same financial statement line item as the hedged items.
Changes in fair values for derivative instruments not designated in a hedge accounting relationship are recognized directly in our results of operations each period and on the same financial statement line item as the hedged item. For purposes of measuring segment operating performance, the net gain (loss) from the changes in fair value of our undesignated commodity derivative contracts, prior to settlement, is reported outside of segment operating results until such time that the underlying exposure is recognized in the segment operating results. Upon settlement, the net gain (loss) from the changes in fair value of the undesignated commodity derivative contracts is reported in the appropriate operating segment, allowing our operating segment results to reflect the economic effects of the commodity derivative contracts without the resulting unrealized mark to fair value volatility.
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67,971
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https://cdla.io/permissive-1-0/
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determination, we consider various existing economic and market factors, business strategies as well as the nature, length, and terms of the agreement. Based on our evaluation using these factors, we concluded that the exercise of renewal options or early termination options would not be reasonably certain in determining the lease term at commencement for leases we currently have in place. Assumptions made at the commencement date are re-evaluated upon occurrence of certain events such as a lease modification.
Certain of our contractual arrangements may contain both lease and non-lease components. We elected to measure the lease liability by combining the lease and non-lease components as a single lease component for all asset classes.
Certain of our leases include variable lease payments, including payments that depend on an index or rate, as well as variable payments for items such as raw materials, labor, property taxes, insurance, maintenance, and other operating expenses associated with leased assets. Certain grape purchasing arrangements include variable payments based on actual tonnage and price of grapes. In addition, certain third-party logistics arrangements include variable payments that vary depending on throughput. Such variable lease payments are excluded from the calculation of the right-of-use asset and the lease liability and are recognized in the period in which the obligation is incurred.
## Indemnification liabilities
We have indemnified respective parties against certain liabilities that may arise in connection with certain acquisitions and divestitures. Indemnification liabilities are recognized when probable and estimable and included in deferred income taxes and other liabilities (see Note 16).
## Stock-based employee compensation
We have two stock-based employee compensation plans (see Note 18). We apply grant date fair-value-based measurement methods in accounting for our stock-based payment arrangements and recognize all costs resulting from stock-based payment transactions, net of expected forfeitures, ratably over the requisite service period. Stock-based awards are subject to specific vesting conditions, generally time vesting, or upon retirement, disability, or death of the employee (as defined by the plan), if earlier. For awards granted to retirement-eligible employees, we recognize compensation expense ratably over the period from the date of grant to the date of retirement-eligibility.
## Net income (loss) per common share attributable to CBI
We have two classes of common stock with a material number of shares outstanding: Class A Common Stock and Class B Convertible Common Stock (see Note 17). In addition, we have another class of common stock with an immaterial number of shares outstanding: Class 1 Common Stock (see Note 17). If we pay a cash dividend on Class B Convertible Common Stock, each share of Class A Common Stock will receive an amount at least ten percent greater than the amount of the cash dividend per share paid on Class B Convertible Common Stock. Class B Convertible Common Stock shares are convertible into shares of Class A Common Stock on a one-to-one basis at any time at the option of the holder.
We use the two-class method for the computation and presentation of net income (loss) per common share attributable to CBI (hereafter referred to as “net income (loss) per common share”) (see Note 19). The two-class method is an earnings allocation formula that calculates basic and diluted net income (loss) per common share for each class of common stock separately based on dividends declared and participation rights in undistributed earnings as if all such earnings had been distributed during the period. Under the two-class method, Class A Common Stock is assumed to receive a ten percent greater participation in undistributed earnings (losses) than Class B Convertible Common Stock, in accordance with the respective minimum dividend rights of each class of stock.
Net income (loss) per common share – basic excludes the effect of common stock equivalents and is computed using the two- class method. Net income (loss) per common share – diluted for Class A Common Stock reflects the potential dilution that could result if securities or other contracts to issue common stock were exercised or converted into common stock. Net income (loss) per common share – diluted for Class A Common Stock is computed using the more dilutive of the if-converted or two-class method. Net income (loss) per common
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