Revenue / Lease Standard

Revenue / Lease Standard Introduction: The IADC AIP Revenue and Lessor Subcommittee have sought to evaluate the revenue recognition standard under Topic 606 and the lease standard under Topic 842 for applicability to the earnings process for drilling contractors by evaluating the requirements of the standards against the terms of a standard drilling contract. Adoption: In consideration of our standard drilling contracts, Topic 606 and Topic 842 are effective January 1, 2018 and January 1, 2019, respectively. However, for Topic 842 early adoption is permitted. Given the potential financial statement impacts of both standards on the earnings process for drilling contractors, we plan to adopt both standards concurrently, including early adoption of Topic 842, on January 1, 2018. Discussion point: As we plan to adopt Topic 606 and Topic 842 at the same time, what is the appropriate or preferred transition method for adoption? Analysis: Topic 606 allows for transition using either a retrospective method or a cumulative effect method. Under the retrospective method, the standard may be applied in a full retrospective manner or with certain practical expedients that provide relief from applying the requirements of Topic 606 to certain types of contracts in the comparative periods presented. Topic 606 also allows for a cumulative effect transition method, which includes recording a cumulative effect of the standard in equity at the beginning of application without restatement of comparative period amounts. However, certain comparative period disclosures are required. Topic 842 only allows a retrospective method of transition. However, certain practical expedients are available which provide relief in applying the standard to contracts in comparative periods including: 1. Practical expedient to elect not to reassess: a. Whether expired or existing contracts meet the new lease definition b. Lease classification for expired or existing leases; and c. Whether previously capitalized indirect costs would be capitalized under Topic 842 These practical expedients must be elected as a package and applied to all leases. 2. Practical expedient to use hindsight: a. In determining the lease term, and assessing the likelihood that a lessee purchase option will be exercised; and b. For lessees, in assessing the impairment of right-of-use assets Given the practical expedients available and the desire to provide comparable financial statements, consideration should be given to what may be the preferred method of transition when adopting both Topics 606 and 842. Standard Drilling Contract Terms The rig contractor provides a rig meeting the specified drilling program criteria and performs drilling services including providing a full crew to operate and maintain the rig. The customer determines the location to drill and the specified depth of each well. DRAFT FOR DISCUSSION PURPOSES ONLY 1

A standard drilling contract typically includes most, if not all, of the following: Contract term the specified amount of time necessary to complete the drilling program (e.g. number of wells, number of operating days); Compensation for drilling services consideration received typically is in the form of a day rate paid for each operating day. During periods of equipment breakdown and repair, during re-drilling, or suspension of operations for other specified conditions, lower rates (i.e. standby rate, repair rate, moving rate, re-drill rate, weather rate, etc.) or no rates (i.e. zero rate) may apply; Mobilization and demobilization requirement to move the rig to the planned drilling site prior to commencement of drilling services and to remove the rig upon completion. Contract terms may include reimbursement of the associated costs by the customer through up-front payment, additional day rate over the contract term, or direct reimbursement; Reimbursable provisions allowing the recovery of certain labor and other operating cost increases, capital upgrades, and certain cost increases due to changes in law, from the customer through up-front payment, additional day rate over the contract term, or direct reimbursement; Performance bonuses additional performance based consideration. Contract extension/renewal options allowing the extension of the contract term. The option is generally exercisable upon advance notice, at mutually agreed rates; and Termination provisions allowing for the termination of the drilling contract for cause or convenience (in certain cases obligating the customer to pay an early termination fee); As our drilling services contracts drive our revenue financial statement line item, Topic 606 is the starting point in our analysis of these contracts. However, ASC 606-10-15-4 states that if a contract with a customer is partially within the scope of other Topics (including leases) that specify how to separate and/or initially measure one or more parts of the contract, then an entity shall first apply the separation and/or measurement guidance in those Topics. As such, we first determine if a standard drilling contract contains a lease as defined under Topic 842. Definition of a lease Topic 842 defines a lease as a contract that conveys the right to control the use of identified property, plant, or equipment (an identified asset) for a period of time in exchange for consideration. The key consideration points under this definition are (1) the identified asset and (2) the right to control the use of this asset. Identified asset A contract contains an identified asset if (1) there is a specified asset in the contract, (2) that asset is physically distinct or that the customer has the right to receive substantially all of the capacity of that asset and (3) the supplier does not have substantive substitution rights. A standard drilling contract explicitly specifies a physically distinct asset (i.e. the drilling rig) to be used to execute the customer s stated drilling program and only that drilling program during the contract term. While as the supplier we may have the right to substitute one drilling rig for another throughout the contract term, in order for the rig to not be an identified asset, that right must be substantive. To determine whether a substitution right is substantive, each of the following is considered: 1. Does the supplier have the practical ability to substitute alternative assets throughout the period of use? This ability is evidenced by: DRAFT FOR DISCUSSION PURPOSES ONLY 2

a. Can the customer prevent the supplier from substituting the asset? While alternative drilling rigs that meet a drilling program s specifications may be available, we would not typically substitute a rig without the consent of the customer. b. Are alternative assets readily available or could they be sourced by the supplier within a reasonable amount of time? While alternative drilling rigs that meet a drilling program s specifications may be readily available, we would typically not substitute the asset unless there were necessary repairs to return it to working condition. Even then, it would typically take longer to mobilize an alternative drilling rig to the drilling location than it would to repair the rig. 2. Would the supplier benefit economically from exercising its right of substitution (i.e. economic benefits exceed the costs)? Generally the costs of mobilizing an alternate rig to a drilling location will exceed the cost of repairing the rig or any economic benefits of substituting the drilling rigs. While judgment is involved in evaluating the terms of each individual drilling contract, we believe any substitution rights would not be substantive and a drilling rig would be considered an identified asset in a standard drilling contract. Customer controls the use of the identified asset A customer controls the use of the identified asset when they have both the right to (1) obtain substantially all of the economic benefits from the use of the identified asset and (2) direct the use of the identified asset throughout the period of use. 1. Does the customer have the right to obtain substantially all of the economic benefits? In a standard drilling contract the customer typically has exclusive use of the drilling rig throughout the term and as a result has the right to obtain all of the economic benefits from its use. 2. Does the customer have the right to direct the use of the asset? A customer has the right to direct the use of an identified asset when it has the right to direct how and for what purpose the asset is used throughout the term. This evaluation focuses on whether the customer has control over those decision-making rights that are most relevant to the economic benefits to be derived from the asset s value (i.e. the what, when, where and how much decisions). In a standard drilling contract, the customer decides the location and depth of the well to be drilled by the drilling rig. While the contractor controls the personnel, operations and safety on the rig that can impact the speed at which the operational goals are obtained, the decisions around location and depth are considered most influential to the economics of the drilling program, i.e. whether oil or gas is discovered in that location that can be extracted and sold. The contractor s rights under the contract are typically intended to protect the drilling rig, protect our personnel or comply with laws or regulations (i.e. protective rights). These rights typically define the scope of the customer s right to use the drilling rig but do not prevent the customer from directing the use of the drilling rig. Discussion point: There seems to be a narrow scope exception for contracts where the drilling specifications are clearly defined in the contract and could preclude the determination of the contract containing a lease. Even if that is the case, there are still conditions that would require lease determination. Are any drillers planning to avail themselves of this scope exception such that it should be included in this position paper? The supplier nor the customer may control the relevant decisions to be made about how and for what purpose the underlying asset is used when those decisions are predetermined by the terms of the contract (i.e. by the DRAFT FOR DISCUSSION PURPOSES ONLY 3

design of the asset or by contractual restrictions on its use). However, even if the relevant decisions about how and for what purpose the asset is used are predetermined in the contract, the customer has the right to direct the use of the asset if at least one of the following conditions exists: 1. It has the right to operate the drilling rig or direct others to operate it in a manner it determines throughout period of use without the supplier having the right to change those operating instructions; or 2. It designed the drilling rig in a way that predetermines how and for what purpose it is used throughout the period of use. It is expected that there will be relatively few situations, if any, where all of the substantive decisions about how and for what purpose the drilling rig is used will be predetermined in the contract. If such decisions are predetermined, careful consideration should be given to all the relevant facts and circumstances when evaluating control. Similar to previous lease guidance, the determination of whether a contract contains a lease is largely based on the concept of control. In the previous lease guidance, one of the ways a customer conveyed control over the use of the asset included operating the asset or directing others to operate the asset in a manner it determines while receiving more than a minor amount of the economic benefit. As a standard drilling contract does not convey the right to operate our drilling rigs to the customer we asserted that under previous lease guidance our contracts do not contain a lease, but instead are service agreements. Under Topic 842 the concept of control, consistent with Topic 606, progressed beyond simply the right to operate the asset (i.e. protective rights) to include the determination of who has the ability to direct the use of that asset (i.e. the relevant decision making rights that drive the economic benefits) and it is this change that drives the conclusion that standard drilling contracts contain a lease under the new standard. As a standard drilling contract falls under the scope of Topic 842, we will evaluate and apply the following lease guidance for lessors: 1. Identify and separate the lease and non-lease (i.e. service) components; 2. Measure the consideration in the contract (as defined under Topic 842); 3. Allocate the consideration in the contract between the lease and non-lease components; and 4. Classify the lease. The identification and evaluation of these elements of the lease guidance begins at the inception of the contract. Under Topic 842, recognition begins at the commencement date of the lease which is defined as the date on which a lessor makes an underlying asset available for use by the lessee. We are typically required to mobilize the drilling rig to the drilling location or at times be required to perform capital upgrades prior to beginning drilling operations. Under Topic 842, the commencement date, as it is defined, is not affected by either the beginning of operations or the timing of lease payments under the terms of the lease. Instead, the commencement date corresponds to the date the underlying asset is made available (i.e. the date the lessee may take possession or be given control over the use of the underlying asset). Typically, any capital upgrades being made to the drilling rig before operations begin are performed in a shipyard at the direction of the contractor to the specifications laid out in the contract prior to making the drilling rig available to the customer. While the customer has the right to inspect the drilling rig while in the shipyard, these rights do not constitute control of the drilling rig during this time period. Furthermore, while the drilling location has been determined by the customer, the drilling rig has not DRAFT FOR DISCUSSION PURPOSES ONLY 4

been made available for use (i.e. control transferred) until mobilization of the drilling rig to the specified drilling location and acceptance testing at the well site has occurred. The customer does not control the asset during mobilization and cannot change the specified location without amending the contract. As such, the commencement date in a standard drilling contract is typically when the drilling rig, including any capital upgrades, has been mobilized to the drilling location, acceptance testing has occurred and is available to begin drilling operations. Identify the lease and non-lease components Separation and initial measurement is based on Topic 842. The first step in the guidance requires the identification of separate lease components. Lease components The right to use an underlying asset is a separate lease component if: 1. The lessee can benefit from the lease on its own or together with other resources that are readily available to the lessee; and 2. The lease is neither highly dependent on, nor highly interrelated with, the other leases in the contract. As the only item that meets both of these criteria in a standard drilling contract is the drilling rig, it is identified as the sole lease component under Topic 842. Non-lease components A contract might contain non-lease components in addition to lease components. Non-lease components consist of items or activities, not identified as lease components, that transfer a good or service to the lessee. As such, the drilling services we provide have been identified as the non-lease component in a standard drilling contract. Not a component Not every element of a contract that contains a lease is necessarily a component. Activities or lessor costs that do not transfer a good or service to the lessee are not considered components of the contract. Examples include a lessee s reimbursement or payment of the lessor s property taxes and insurance. This is intended to be consistent with the guidance in Topic 606 relating to set-up or other activities that do not transfer a good or service to the customer. Consistent with treatment under current GAAP, we believe mobilization (i.e. delivery of the asset to the well site), demobilization (i.e. removal of the asset from the well site) and capital upgrades (i.e. upgrading the asset for its intended use) do not transfer a good or service to the customer and as such should be considered not a component under Topic 842. At times we may be reimbursed for certain labor and other operating costs, or for supplies or expenses purchased on behalf of the customer. These reimbursable payments are typically variable and based on the broad scope of reimbursable items, may be related to the drilling rig, drilling services, both or neither. Given the various circumstances in which we reimbursable provisions may exist in our contracts we believe consideration should be given to those circumstances on an individual basis. Measure the consideration in the contract Once the components of a standard drilling contract have been identified, the next step under Topic 842 is to measure the consideration in the contract. The consideration in the contract includes any of the following: DRAFT FOR DISCUSSION PURPOSES ONLY 5

1. Fixed payments relating to use of the underlying asset; 2. In-substance fixed payments; 3. Variable payments that depend on an index or rate; 4. Variable payments that are not specifically or partially related to the lease component that do not depend on an index or rate. 5. Exercise price of an option to purchase the underlying asset if the lessee is reasonably certain to exercise that option; 6. Payments for penalties for terminating the lease if the lease term reflects the lessee exercising an option to terminate the lease. The consideration in the contract excludes any of the following: 1. Variable lease payments other than those described above 2. Any guarantee by the lessee of the lessor s debt Consideration includes the following: Fixed payments relating to the use of the underlying asset Any fixed consideration received (i.e. pre-commencement payments for mobilization, capital upgrades or other reimbursable items) is included in measuring the consideration in the contract whether it relates to an item being identified as a component of the lease or not. In-substance fixed payments In-substance fixed payments are payments that may, in form, appear to contain variability but are, in effect, unavoidable. They may include for example, either of the following: 1. Payments that do not create genuine variability (such as those that result from clauses that do not have economic substance) 2. The lower of the payments to be made when a lessee has a choice about which set of payments it makes, although it must make at least one set of payments. In-substance fixed payments are included in the measurement of lease payments because they are unavoidable and therefore economically indistinguishable from fixed lease payments. The clauses in our contracts regarding variable consideration are meant to share the risks and rewards of the drilling program and therefore have economic substance. Applicability of different day rates in different circumstances creates genuine variability. At commencement of the lease, it is most advantageous for both the contractor and the customer if the full operating rate is experienced throughout the duration of the contract. Although the customer has the ability to institute a lower rate at the standby rate, doing so would only prove to increase the overall cost of the project as each drilling program requires a certain amount of operational time to complete. Even contracts with a time-based term will not stop in the middle of the drilling program as there are provisions in the contract to extend the contract term to compete the well program. Therefore, if the lessee has a choice about which payments it makes, from the rates it has the ability to control, it would choose to execute the project according to plan at the full operating rate. DRAFT FOR DISCUSSION PURPOSES ONLY 6

However, drilling conditions dictate a majority of the applicable day rates, more so than the choice of the customer or contractor. These uncertainties in drilling conditions equate to uncertainties about the rate that will apply throughout the duration of the contract. As no two drilling programs are alike, the variation in day rate is meant to adequately share the risks associated with the drilling process between the two parties. The variability in applicable day rates is not simply related to whether the rig is working or not, but is typically tailored for the potential drilling conditions of the location specified by the customer. While the performance and condition of the rig determines a majority of the applicable day rates, the applicable rates can range from zero to full operating rate despite the rigs operating condition. Included within this range are zero rates that may be applicable in a variety of situations including ones within or outside of our control. Examples of zero rate situations within our control include: 1. Being on repair rate in excess of the number of days allowed in the contract; 2. Inadequate number of personnel onboard; 3. Planned certifications, surveys and inspections required by regulators; and 4. Planned preventative maintenance in excess of the number of days allowed in the contract Examples of zero rate situations outside of our control include: 1. Being subject to wait on weather rate in excess of the number of days allowed in the contract (which can also encompass sub-surface conditions like loop currents); 2. Unplanned certifications, surveys and inspections required by regulators; 3. Third party requirements to replace rig parts (e.g. lifting of BOP to replace rubber goods as required by the Bureau of Safety and Environmental Enforcement BSSE ); and 4. Repairs related to changes in well site conditions (e.g. well shifting or cratering) not attributable to our actions Furthermore, included in this range may be circumstances where the rig can earn the full operating rate while under repair as well as circumstances where the rig can earn a zero rate in a fully operational condition. Historically, our actual rig utilization throughout the contract as a result of the uncertain drilling conditions in which we operate (i.e. zero and other reduced rate scenarios) is often times lower than the standby rate (i.e. 95% of the operating rate). The related rate we actually realize based on utilization is determined on an hourly basis by the varying rates applicable each day, ranging anywhere from a zero rate to a full operating rate. In the Basis of Conclusion section under Topic 842, board members had discussions to determine whether or not the measurement of the lease payment should include some sort of probability-weighted estimation, noting that doing so would be difficult for cost-benefit and precision reasons. As such, no such estimation approach was included under Topic 842 when measuring the consideration in the contract.. Based on our consideration of Topic 842 and other relevant material, we believe that day rate payments under a standard drilling contract are: 1. Considered variable lease payments under Topic 842 based on the uncertainties drilling conditions provide and the various impacts to the performance or use of our drilling rigs by our crew and 2. Do not qualify as in-substance fixed payments as there is no minimum guaranteed payment amount. DRAFT FOR DISCUSSION PURPOSES ONLY 7

As such, we believe the variable day rate payments should be excluded from determining the consideration in the contract for purposes of measuring the lease classification. Further, as day rate consideration is not included, contract renewals or extension periods will not factor into the consideration where a variable day rate is involved. Variable payments that depend on an index or rate Standard drilling contracts typically do not contain provisions for variable payments that depend on an index or rate. Variable payments that are not specifically or partially related to the lease component that do not depend on an index or rate Standard drilling contracts typically do not contain provisions for variable payments that are not in some way tied to the lease component or use of the rig. At times we may receive additional variable payments based on specific performance criteria outlined in the contract. Typically, these performance measures incorporate the performance of both the drilling rig and the crew and as such any variable payments would not be included in the consideration in the contract under Topic 842. In instances in which the performance measure is attributable to the crew only (i.e. service component) then the variable payments would be estimated and the consideration recognized in accordance with Topic 606. Exercise price of an option to purchase the underlying asset if the lessee is reasonably certain to exercise that option Standard drilling contracts typically do not provide for purchase options. Payments for penalties for terminating the lease if the lease term reflects the lessee exercising an option to terminate the lease. Standard drilling contracts will typically provide for some termination provisions for convenience (more onerous to the customer) or cause. At the commencement of the lease, these termination provisions are reasonably certain not to be exercised and therefore any related consideration is excluded from the evaluation of the contract. Consideration does not include the following: Variable lease payments. Based on the above, day rate is considered variable and not included in the consideration in the contract. Any guarantee by the lessee of the lessor s debt Standard drilling contracts typically do not contain provisions for guarantees of the lessor s debt. Allocate the consideration to lease and non-lease components In following the guidance in Topic 606, as instructed in Topic 842, the consideration in the contract is allocated to each separate lease and non-lease component to depict the amount of consideration expected to be entitled to. The consideration in the contract is generally allocated to each separate lease and non-lease component on a relative basis in proportion to its stand-alone selling price, which is determined first by the observable price. If there is no observable price available, an estimate is used based on the following: 1. Adjusted market assessment approach evaluate the market in which goods or services are sold and estimate the price that customers in the market are willing to pay; 2. Expected cost plus a margin approach forecast the expected costs of satisfying a performance obligation and then add an appropriate margin for that good or service; or DRAFT FOR DISCUSSION PURPOSES ONLY 8

3. Residual approach (used in limited circumstances) subtract the sum of the observable stand-alone selling prices of other goods or services promised in the contract from the total transaction price. While the consideration in the contract may include fixed amounts related to items identified as not a component (i.e. mobilization, demobilization, capital upgrades and reimbursables), these amounts are allocated only to the separate lease and non-lease components. Furthermore, variable lease payments not included in the consideration in the contract are allocated to the separate lease and non-lease components consistent with the allocation decisions regarding the consideration in the contract. Determining the appropriate allocation approach may vary based on a company s individual facts and circumstances and the information available to them; however, the following potential inputs may be considered: 1. Transfer pricing studies 2. Services performed without a lease component (i.e. management service contracts) Discussion point: Discuss the various allocation scenarios mentioned by Transocean. Classify the lease The next step under Topic 842 is for lease classification. Lease classification is determined for each separate lease component (i.e. the drilling rig under a standard drilling contract) at the lease commencement date. The lease classification criteria under Topic 842 are similar to current U.S. GAAP without the use of explicit bright lines (i.e. 90% present value test and 75% economic life test). The criteria include: 1. The lease transfers ownership of the underlying asset to the lessee by the end of the lease term. A standard drilling contract does not typically transfer ownership of the drilling rig at the end of the lease. 2. The lease grants the lessee an option to purchase the underlying asset that the lessee is reasonably certain to exercise. A standard drilling contract does not typically include purchase options for the drilling rig. 3. The lease term for a major part of the remaining economic life of the underlying asset. The lease term is considered the noncancellable period of the lease and includes periods covered by an option to extend the lease if the lessee is reasonably certain to exercise that option as well as periods covered by an option to terminate the lease if the lessee is reasonably certain not to exercise the option. There may be instances when the lease term may be a major part of the remaining economic life. However, Topic 842 provides an exception to this test if the commencement date is at or near the end of the asset s economic life (i.e. 25% of total economic life). We anticipate a rare circumstance where an older rig, not yet in the remaining 25% of its economic life, would obtain a long-term contract that would exceed 75% of the remaining economic life and will need to be considered on a case by case basis. 4. The present value of the sum of (1) the lease payments (all contract consideration allocated to the lease, whether identified as a lease component, service component or not a component) and (2) any lessee residual value guarantee, equal or exceed substantially all of the underlying asset s fair value. Standard drilling contracts typically do not include residual value guarantees. As a result, this test won t be met as we have concluded that the day rate payments are variable payments excluded from the consideration in the contract and as such, are not included in the lease payments for classification purposes. DRAFT FOR DISCUSSION PURPOSES ONLY 9

5. The underlying asset of such a specialized nature that it is expected to have no alternative use to the lessor at the end of the lease term. We expect drilling rigs to have use for other oil companies at the end of contractual drilling periods. Evaluating the lease classification criteria in 842-10-25-2 as a lessor, a standard drilling contract typically does not meet any of the above criteria and as such, is classified as an operating lease. Recognition After applying the separation and measurement guidance under Topic 842, we must consider the various components of the contract to determine the applicable recognition guidance (i.e. Topic 606 or Topic 842). Topic 842 Recognition As a standard drilling contract is classified as an operating lease, at lease commencement the contractor would continue to recognize the drilling rig as an asset and depreciate it over its estimated useful life. Any precommencement payments (e.g. mobilization) would be deferred. Subsequently, any lease payments (i.e. related to any fixed consideration received) are recorded as receivables when due and payable by the lessee. Fixed or variable consideration amounts included in the contract and allocated to the lease component (i.e. lease revenue), whether deferred or not, are recognized on a straight-line basis over the lease term. Variable lease payments are recognized as income in profit or loss as the variability is resolved (i.e. as performance or use of the asset occurs). Topic 606 Application and Recognition Topic 606 is applied to fixed or variable consideration amounts included in the contract and allocated to the service component. Under Topic 606 revenue is recognized when, or as, an entity satisfies a performance obligation (i.e. transferring a promised good or service to a customer). Under a standard drilling contract, as it relates to the consideration in the contract allocated to the service component, the performance obligation identified is being available to perform drilling services. Under a standard drilling contract we perform drilling services ratably over the contract term. As such, Topic 606 requires a recognition method (i.e. measure of progress) that depicts our performance or transfer of drilling services to the customer. We believe the appropriate measure of progress in relation to the satisfaction of the performance obligation is time elapsed (i.e. the number of hours/days we provide drilling services). As such, the revenue related to the fixed or variable consideration in the contract allocated to the service component is recognized as we perform drilling services over time, typically on a per day basis. Initial direct costs / Costs to obtain a contract Under Topic 842 initial direct costs are defined as incremental costs of a lease that would not have been incurred if the lease had not been obtained and is consistent with the definition and accounting treatment of contract cost guidance under Topic 340-40. Initial direct costs are initially allocated between the lease and non-lease components in a consistent manner with the allocation principles used for lease income and are deferred (i.e. capitalized). Costs allocated to the lease component are amortized and recognized as expense over the lease term on the same basis as lease income (i.e. on a straight-line basis). Costs allocated to the non-lease component are amortized on a systematic basis that is consistent with the measure of progress used in relation to the satisfaction of the performance obligation (i.e. time elapsed). Presentation Consideration will need to be given to the presentation of revenue on the face of the income statement based on the materiality of lease income and the relating SEC filing requirements. DRAFT FOR DISCUSSION PURPOSES ONLY 10

SEC Regulation S-X section 210.5-03(b) states if income is derived from more than one of the subcaptions described under section 210.5-03.1, each class which is not more than 10 percent of the sum of the items may be combined with another class. If these items are combined, related costs and expenses as described under section 210.5-03.2 shall be combined in the same manner. Based on the relevant SEC guidance and the allocation of consideration, we expect that sufficient consideration would be allocated to each revenue generating activity (Lease revenue and Service revenue) such that it would require separate line items on the face of the income statement. Disclosure Consideration will need to be given to the disclosure requirements based on the new standards. Discussion point: How will Topics 606 and 842 impact our disclosure requirements? What disclosures for Topic 606 would apply, if any? Should these disclosure requirements be addressed in this position paper? Conclusion: Both Topic 606 and 842 call for expanded qualitative and quantitative disclosure requirements. We are currently evaluating these requirements including the interplay between the two standards to determine the potential changes to our current financial statement disclosures. Overall, application of the new revenue and lease accounting standards results in a revenue recognition pattern largely similar to what we have today under current accounting guidance with additional presentation and disclosure requirements. DRAFT FOR DISCUSSION PURPOSES ONLY 11