United Kingdom Oil and Gas Taxation
The current United Kingdom oil and gas taxation regime is extremely complicated and has arisen out of the many changes that have taken place since specific oil tax provisions were introduced in 1975. The UK government has recently been undertaking steps to simplify the regime with a view of making the UK more attractive for foreign investments.
Until Finance Act 2016, there have been three main elements of government take to which companies undertaking oil and gas exploration, development and production activities in the UK or the UK sector of the continental shelf have possibly been subject to being Corporation tax (CT), Supplementary Charge (SC) and Petroleum Revenue Tax (PRT). On 16 March 2016 the Chancellor announced a permanent reduction in the PRT rate to 0% with effect from 1 January 2016.
Corporation tax (CT) is levied at a rate of 30% on the upstream profits of the company as a whole, with those profits after certain adjustments also being subject to Supplementary Charge (SC) which is chargeable at 10% from 1 January 2016.
The marginal rate of these taxes is at present 40% but was 75% prior to 1 January 2016 for those fields which were subject to PRT.
Non-residents with activities in the UK or the UK sector of the Continental Shelf are also subject to Corporation Tax, at normal CT rate of currently 20% (the rate is due to be reduced to 19% from 1 April 2017 and to 17% by 2020), on profits from exploration and exploitation activities.
Corporation tax is levied on a company by company basis. A company with more than one field interest will therefore aggregate the results for those fields and any other activities in arriving at its profits subject to corporation tax.
Corporation tax is levied on the worldwide profits of any company that is tax resident in the United Kingdom. An elective exemption was however introduced for non-United Kingdom permanent establishments of UK-resident companies in Finance Act 2011. Corporation tax is also levied on the profits of any non-United Kingdom resident companies to the extent those profits are attributable to a trade carried on through a permanent establishment situated in the United Kingdom. The scope of the United Kingdom tax net is further extended to bring into charge profits attributable to exploration and exploitation activities in the United Kingdom sector of the continental shelf.
Taxable profits for corporation tax are determined by adjusting normal accounting profits. As a general rule, items of a revenue nature are allowable when incurred and items of a capital nature are treated as disallowable for corporation tax purposes; in addition only costs incurred “wholly and exclusively” for the purposes of the trade are deductible. The most significant adjustment is that no deduction is available for depreciation, but instead relief is given by way of “capital allowances”, i.e. tax depreciation, at specific rates depending on the type of an asset. Since 2002 nearly all expenditure had qualified for immediate relief. PRT is treated as an expense for corporation tax purposes.
For “large” companies corporation tax is payable in instalments. The rate of 30% is applied for ‘ring fence’ profits, and the tax is due on these profits in three quarterly instalments where the return covers the normal 12 month period. The first instalment is due six months and 14 days into the period and the others follow quarterly thereafter. This contrasts with the four instalments and a lower rate in respect of non ‘ring fence’ profits. The instalment payment regime is currently undergoing a review; however the ring fence instalment regime is unlikely to be affected.
The Ring Fence
While all companies operating in the UK are within the corporation tax regime there are some additional rules (the ring fence rules) that relate to upstream oil and gas activities. These ring fence rules are designed to prevent companies reducing their upstream ring fence profits with reliefs and allowances from other activities.
The main restrictions are that losses and expenses from other activities, either within the company or accruing to an affiliate, cannot be deducted against ring fence profits. The deductibility of financing costs is also limited such that, broadly, interest deductions are only available in respect of monies borrowed which have been used in the ring fence business, and where the terms do not exceed those applicable at arm’s length. In applying the rules, the assumption is made that the ring fence business is supported solely by the ring fence assets of the borrower. There are restrictions on the utilisation of capital losses against capital gains, and limitations on the amount of capital allowances that can be claimed on field transfers. However, there are some benefits which are particular for ring fence activities such as Ring Fence Expenditure Supplement (RFES) and Reinvestment Relief.
Other than the above the normal corporation rules are applied to the ring fence activities. There are however a number of areas of the regime that are of particular relevance to upstream activities, which are set out below.
Neither capital expenditure nor the depreciation of those costs is allowable for corporation tax purposes; instead there are specific capital allowances available which are deducted from chargeable profits.
The allowances that are of most relevance to upstream activities are research and development allowances (RDAs), plant and machinery allowances (P&M), and mineral extraction allowances (MEAs). No allowances are available until a company commences to trade, but once it does all capital expenditure incurred prior to commencement is deemed to have been incurred at commencement.
If expenditure is incurred for the purposes of a mineral extraction trade by a company which is about to carry on such trade, the expenditure is treated as incurred by that company on the first day on which that company commences on trading.
RDAs, for which relief at 100% is given, apply to all exploration and appraisal costs until such time as reserves in commercial quantities have been discovered. The costs must be first hand exploration or appraisal costs. No relief under these provisions is therefore available for reimbursing previously qualifying costs or when buying into a licence (but see comments on MEAs below).
The capital cost of production and transportation facilities will generally qualify for plant and machinery capital allowances. Most costs incurred after 16 April 2002 will qualify for immediate 100% relief, including, from 1 April 2008, expenditure on new long life assets used within the ring fence. All qualifying assets are put into a single main pool or a special rate pool with a balancing allowance or charge arising when the last such asset in that category is disposed of, being the difference between the disposal proceeds and the balance of unclaimed allowances at that time. If the assets are acquired as part of a Schedule 17 FA80 field transfer any claim is restricted to the cost of the seller. If the asset is not put into use in the ring fence trade the 100% first year allowance (FYA) will be lost and only writing down allowances (WDA) at 25% p.a. on a reducing balance basis will be available.
Mineral extraction allowances (MEAs) are available for mineral exploration and access expenditures (broadly all expenditures in searching for, discovering, testing, and winning access to the minerals) and on acquiring a mineral asset, but the rates differ between the types of expenditure. Costs incurred on acquiring a mineral asset, and which cannot be attributed to past mineral extraction and access expenditure, qualify for a 10% writing down allowance on a reducing basis and only to the extent, for a UK licence, they do not exceed the amount paid to the Secretary of State to acquire the licence. But mineral exploration and access expenditure in a ring fence trade incurred after 16 April 2002 qualifies for an immediate 100% first year allowance. Costs incurred prior to that, other than on acquiring a mineral asset, qualified for writing-down allowances at 25% per annum on a reducing balance basis. In practice many costs potentially falling under this category will qualify for research and development allowance and will normally be claimed as such, unless the company doesn’t need the relief immediately, but development drilling costs that do not qualify for RDAs are usually claimed under the MEA code. So-called “second-hand” exploration costs (e.g. reimbursements), and any value representing past exploration expenditure on licence acquisitions, qualify for the 100% relief in a ring fence trade. If the 100% FYA is not claimed relief is then available at the 25% per annum reducing balance basis.
Special rules apply to decommissioning expenditure. Costs relating to the demolition of offshore installations and pipelines, onshore installations used primarily for offshore purposes, and certain restoration costs, may qualify for a 100% deduction in the period they are incurred, but for other costs the relief may vary.
The costs of obtaining an abandonment guarantee are expressly allowable where they qualify as deductible for PRT; FA 2013 extended this relief for abandonment guarantee costs incurred on or after 17 July 2013 for costs which are not related to a PRT field.
Trading losses may be carried forward indefinitely and set against future profits of the same trade. Losses may generally be carried back 1 year. To the extent the loss is generated by decommissioning expenditure there is 3 year carry back against total profits and thereafter a carry back to April 2002 against ring fence profits.
Ring Fence Expenditure Supplement
For accounting periods ended after 1 January 2006 Ring Fence Expenditure Supplement (RFES) may be available where a company makes a loss.
The RFES allow companies to claim a 10% (from 2012 – previously 6%) supplement on their ring fence trading losses carried forward for 10 (previously six), not necessarily consecutive, periods. Finance Act 2015 introduced the extension from six to 10 accounting periods; however, the additional 4 claims can only be made in respect of losses incurred post 5 December 2013. The RFES regime is now aligned for both offshore and onshore activities (the extension for onshore activities was originally granted in FA 2014).
Losses attributable to exploration and appraisal expenditures incurred under the old Exploration Expenditure Supplement rules can also be taken into account. Losses are computed on the assumption that all other available reliefs, such as group relief and loss carry back against ring fence profits, are claimed and are reduced to the extent there are ring fence profits elsewhere in the group.
Ring Fence Reinvestment Relief
Capital gains on the sale of licence interests can be exempted from charge under the reinvestment relief rules. This now applies to both companies carrying on a ring fence trade and those who are only exploring or appraising, where the proceeds are reinvested in ring fence assets (including exploration, appraisal and development expenditure for disposals after 23 March 2010) within the four year window commencing one year before and ending three years after the date of disposal.
Substantial Shareholding Exemption (SSE)
The sale of shares in trading companies held by trading groups are exempt if more than 10% of the company’s shares have been held for more than 12 months. Companies carrying on only exploration and appraisal activities are treated as trading companies for these purposes. The 12 month and trading requirements are deemed to be met for disposals after 19 July 2011 where assets are transferred into a new affiliate. This additional relief did not apply if only exploration and appraisal assets were transferred to the affiliate, but this anomaly was remedied in Finance Act 2014 for disposals on or after 1 April 2014.
The SSE rules are currently under review and their scope may be extended in the near future.
The jurisdiction of United Kingdom taxing rights has been extended by statute to the United Kingdom sector of the continental shelf for oil and gas exploration or exploitation activities. Thus, non-residents are subject to United Kingdom tax on any profits from such activities. In practice licence holders will be United Kingdom resident or at least have a permanent establishment in the United Kingdom and therefore be subject to UK tax on their profits. However, non-resident individuals or contractors working offshore will also be subject to United Kingdom tax. Non-residents owning unquoted shares deriving the greater part of their value from United Kingdom exploration and exploitation assets will be subject to United Kingdom tax on the disposal of such shares subject to any exemption under the substantial shareholding exemption rules. Following the Finance Act 2000 changes, assets can be transferred between companies in a worldwide 75 per cent group without incurring a liability provided the asset remains within the charge to UK tax. This rule arguably, however, only applies to “ring fence” assets on transfers of assets between companies resident in the same jurisdiction or from a non-United Kingdom resident company to a United Kingdom resident company. The transfer of ring fence assets from a UK to a, say, Dutch affiliate could still therefore arguably be taxable, as could a transfer from, say, a Norwegian company to a French affiliate.
Bringing non-residents who have little or no contact with the United Kingdom within the scope of United Kingdom tax clearly creates a collection problem. To overcome this any tax assessed on a non-resident which is not paid can be collected from the holders of the licence in respect of, or in connection with, which the profits were made.
Finance Act 2014 introduced a cap on the deduction that can be claimed for bareboat lease rentals paid to affiliates by offshore contractors working in the UK sector of the Continental Shelf, in respect of drilling or accommodation vessels with a market value of more than £2m, against the profits earned from those vessels. The cap is 7.5% of the original cost of the vessel with any excess only being deductible against other profits of the contractor. There are also anti-avoidance provisions to prevent the rules being circumvented by the oil and gas company leasing the vessel direct from the owner.
There are specific rules for arriving at the market value of disposals of both oil and gas for PRT purposes, even if the disposal is from a non-taxable field. The normal corporation tax transfer pricing rules are overridden in this circumstance and the “PRT” values are used for corporation tax purposes.
If any transaction crosses the ring fence boundary, even within a single entity, arm’s-length prices must be applied if ring fence profits would otherwise be reduced. Furthermore, if oil and gas is sold to a party where there is more than a 20% ownership connection, arm’s-length prices have to be applied (assuming the agreed PRT value is not imposed if the sale is also non-arm’s-length for PRT purposes).
A supplementary charge (SC) applies to ring fence profits accruing from 17 April 2002. The current rate of SC is 10%, which has been introduced by Finance Act 2016 from 1 January 2016.
The rate of SC has undergone a number of changes over the years reflecting the oil and gas economic climate. The rate was originally 10% in 2002, was increased to 20% in 2006, and to 32% in respect of profits accruing after 23 March 2011, until the rate was reduced back to the pre-2011 level of 20% for accounting periods beginning on or after 1 January 2015. The rate was further reduced to 10% for accounting periods beginning on or after 1 January 2016.
The tax base is the ring fence profits of the company chargeable to CT after removing all financing costs and deducting any field, cluster or investment allowances available (see Field and Investment Allowances section below). Relief for decommissioning expenditure for work undertaken after 21 March 2012 is however limited to 20% in the periods when the rate exceeded the 20% threshold. This is achieved by grossing up the profits otherwise subject to SC by a fraction of the amount by which the profits have been reduced by decommissioning costs.
For these purposes financing costs include, in addition to straight forward interest costs, exchange gains and losses on debt finance, any derivative contract gains and losses related to debt finance, the financing cost implicit in finance lease or long funding lease arrangements, any other costs treated as financing costs under GAAP.
A strict reading of the original legislation would suggest that capital gains are not subject to supplementary charge. However, HMRC did not accept this interpretation and legislation was introduced in Finance Act 2012 to “clarify” this position such that ring fence gains arising on or after 6 December 2011, including held over gains accruing after that date, are subject to supplementary charge. The legislation as it applied before the change in law was tested before the Courts in 2015 where the HMRC view was upheld.
SC is payable in instalments as with CT.
PETROLEUM REVENUE TAX
The rate of PRT has been set at zero percent with effect from 1st January 2016. The rate was 50% for many years until it was permanently reduced by Finance Act 2016. PRT was introduced in 1975 when the rate was originally 45%, increased to 60% in 1979, then to 70% in 1980, 75% in 1983; the rate was reduced to 50% from 1993. PRT has been abolished for all fields for which development consent was granted on or after 15 March 1993, but has continued to apply to older fields (subject to the field owners being able to demonstrate that no PRT will be payable).
Although the rate of PRT has been set at zero with effect from 1 January 2016 all of the relevant provisions remain.
PRT is computed on a field by field basis by reference to six-monthly chargeable periods ending on 30 June and 31 December each year.
Gas sold to British Gas under contracts signed before 1 July 1975 and oil appropriated for field production is exempt.
PRT is computed on the value of oil and gas produced less allowable costs and reliefs.
Each field is a separate taxable unit. So each licensee must produce a separate return for each field in which it has an interest, and the return will include only income and expenses for that field. There are, however, a number of non-field reliefs available.
PRT is also computed by reference to certain tariff receipts and disposal receipts on assets whose cost has qualified for PRT relief.
To determine the value of oil and gas sold, there is a distinction between arm’s length and non-arm’s length sales. For arm’s length sales the actual sales proceeds are used. For non-arm’s length disposals or appropriations (other than for production purposes) the market value, as determined by HMRC, is brought in. A ‘nominations’ system determines whether an arm’s length valuation may be used for arm’s length sales which are delivered into certain types of forward contract (“BFOE” contracts). If a sale is within the nomination scheme, but is not correctly nominated, the higher of the HMRC market value and actual realised price should be included in the PRT return.
Tariff receipts are chargeable to PRT insofar as they relate to the use of, or services provided in connection with the use of, a qualifying asset. “Qualifying assets” are those assets, expenditure on which has attracted actual or deemed PRT relief, except for non-dedicated mobile assets. Any proceeds from the disposal of a qualifying asset are also brought into charge. An exception to this rule is that tariffs from fields receiving development consent after 8 April 2003 (or older fields that have not used other fields’ infrastructure before that date) are exempt if the tariff agreement was entered into after 8 April 2003. Relief for costs in respect of earning such “TETR” tariffs is however restricted.
Taxable tariff receipts in respect of extraction, transport, initial treatment, or initial storage of oil won otherwise than from the principal field attract a throughput allowance (known as tariff receipt allowance or TRA) where the “user” field is also a taxable field, i.e. a field determined before 16 March 1993. Tariffs earned in respect of the first 250,000 metric tonnes of throughput per chargeable period from each taxable user field are effectively exempt from charge. The allowance cannot create a loss.
PRT is also extended to charge tariff and disposal receipts earned by licensees in non UK fields to the extent that the tariff or disposal receipts relate to assets situated in the UK sector of the continental shelf and those assets are used by UK fields.
PRT cost allowances essentially give relief in full for expenditure as incurred, regardless of whether the expenditure is of a ‘revenue’ or ‘capital’ nature. Claimed expenditure is only deductible against income once it has been determined as allowable by HMRC. The reliefs can be summarised as follows:
Most costs of exploring, appraising, developing, producing, measuring and selling oil won, and decommissioning a field will be qualifying costs. In respect of exploration costs, relief is given if the “searching” is undertaken within 5,000 metres of the field boundary, notwithstanding the costs may not be related to that field.
Relief is given in full in the first relevant period other than for expenditure incurred on non-dedicated mobile assets or expenditure on remote associated assets. A mobile asset is dedicated to a field if it is expected that it will be used in that field for substantially the whole of the asset’s remaining life. If the asset is non-dedicated, relief is only available for that part of the expenditure which relates to periods of use.
Remote associated assets are those put in place purely to earn tariff income, any part of which is situated more than 100 metres from a main field asset, e.g. a spur pipeline. Relief for the cost of such assets is only available against the tariff income (net of TRA) earned from that asset.
A supplementary allowance (uplift) is given at 35% on certain, broadly capital, expenditure, including the majority of costs incurred in bringing the field into production, plus any costs incurred after first oil in substantially improving the rate at which oil can be won from the field. However, uplift only applies to qualifying expenditure incurred prior to payback i.e. when cumulative income exceeds cumulative expenditure plus uplift.
The main non-deductible items for PRT are: financing costs; the cost of acquiring land or interests in land; certain buildings, e.g. administrative offices; de-ballasting; expenditure that depends on the results of the field, e.g. a royalty interest; payments to obtain interests in oil, e.g. licence acquisitions from other licensees; expenditure met by subsidy.
To the extent expenditures (plus uplift) in any chargeable period exceed income the resultant loss can be carried forward or back indefinitely.
Where costs are incurred partly for a qualifying field purpose and partly for another purpose then an apportionment must be made. To the extent that costs are incurred to generate a taxable tariff this is treated as a qualifying PRT purpose. Costs associated with generating non-taxable tariffs are not allowable. In this case HMRC generally operate a “safe-harbour” approach whereby the cost disallowance is restricted to 50% of the tariff.
Although the taxable unit is the field, certain expenditures incurred otherwise than in respect of that field are nevertheless allowable.
This is available for expenditure in offshore taxable fields outside the Southern Basin where development consent was given after 16 March 1987. Up to 10% of qualifying expenditure (basically that which would qualify for uplift – see above) incurred after that date may be set against PRT profits from another field in the same group. However, uplift is foregone on the expenditure claimed.
Research expenditure relief
Research costs that do not become allowable with respect to a specific field within three years of being incurred but which have an application to taxable fields may be set against the participator’s PRT profits from any field (but not those of an affiliate).
Unrelievable field loss relief
If, following the cessation of production from a field, there is a cumulative loss (ignoring any oil allowance relief (see below)), that loss may be claimed against the PRT profits of any other field in the same group ownership.
This permits a maximum of 250,000 tonnes per field per chargeable period to be free of PRT, with an aggregate relief of 5 million tonnes available. This allowance is doubled for fields obtaining development approval after 31 March 1982, but is halved for fields onshore or in the Southern basin for chargeable periods ending after June 30 1988. This allowance is shared among the participators in the field. It can only reduce a profit to zero and cannot create a loss.
This relief is aimed at providing a reasonable rate of return on investment after PRT. It limits the PRT payable to a maximum of 80% of the amount by which the “adjusted profit” (broadly the PRT profit from the field before deducting expenditure qualifying for supplement (uplift) and non-field reliefs) exceeds 15% of the accumulated capital expenditure at the end of each period. The accumulated capital expenditure is the cumulative expenditure for the field that has qualified for supplement (uplift). Safeguard applies to all chargeable periods until payback (where it has no practical relevance) and, thereafter, for half as many periods again.
It is thought that no fields would still benefit from this relief even if the rate has not been reduced to zero.
Transfers of field interests
Where licence interests are sold the consideration for the transfer is ignored and the new owner will effectively stand in the shoes of the previous owner (the so called “Schedule 17 rules”).
Payment of PRT
The current rate of PRT is 0% for chargeable periods ending after 31 December 2015.
Previously, the rules required payments on account and instalment payments of PRT. Estimated PRT liabilities were payable on account two months after the end of the chargeable period, and adjustments dealt with on formal assessment. There was also a system of monthly instalment payments based on the prior period liability, whereby 1/8 of the previous period’s liability is due at the end of the second month of the chargeable period, and at the end of each of the next five months.
Administration of PRT
PRT returns normally have to be filed within two months of the end of each chargeable period, i.e. by the end of February and August each year. The operator also has to submit a separate return (PRT2) which has to normally be made within one month of the end of the chargeable period, detailing the allocation of production, each participator’s share of stocks, and tariff receipts allowance throughput. The main return (PRT1) contains details of all disposals and appropriations in the period together with the values of closing and opening stocks and details of tariff income and disposal receipts. A supplementary return (PRT1A) is also required showing all arm’s length transactions during the period by each company in its group in each type of liquid disposals, other than so-called Category 1 oils, which are not otherwise included in a PRT1 return. This latter return is to help HMRC in their computation of product market values. Since 1999, companies have been able to defer, even indefinitely, the submission of PRT returns where HMRC accept there is no tax at stake in the field. As an alternative it is possible, with prior agreement of HMRC, to file abbreviated returns for chargeable period ended 30 June 2007 and subsequently where again no tax is at stake. Given the rate of PRT has been reduced to zero these rules are being reviewed and may change.
FIELD AND INVESTMENT ALLOWANCES
The original field allowance was introduced in Finance Act 2009, with further allowances following. Until Finance Act 2015, there had been 8 different field allowances. However, following a decision to simplify the Oil & Gas tax regime the government introduced a new basin-wide Investment Allowance which replaces most previously introduced field allowances. In addition, a new Cluster Allowance has been introduced with effect from 1 April 2015. Onshore Allowance which has been previously introduced specifically for onshore ring fence activities has been left unchanged.
The allowances reduce the profits of a company subject to supplementary charge once there has been production from the relevant area to activate the allowance. Investment allowance is shared amongst the participators in accordance with their own expenditure in contrast to the field allowances which were allocated in accordance with equity interest in the field and all are “activated” by production income from the field.
Investment Allowance is calculated as 62.5% of the amount of qualifying ring fence expenditure, which was only capital expenditure when the Investment Allowance was originally introduced, with effect from 1 April 2015. However, the scope of the qualifying expenditure is being extended to include certain operating and leasing expenditure incurred on or after 8 October 2015 (the relevant secondary legislation is yet to be enacted although the government has confirmed that the extension will have retrospective effect).
Once activated by production income including tariff income (the meaning of activation income was extended to include tariff income by Finance Act 2016) from the relevant field the allowance reduces the company’s profits subject to supplementary charge. There are transitional rules which effectively convert unactivated field allowances (eg. Small Field Allowances) into investment allowances with rules to limit expenditure on such fields from qualifying for investment allowance until certain hurdles have been met.
Cluster Allowance is similar to Investment Allowance in the way it is calculated; however qualifying costs for the purposes of Cluster Allowance are those in respect of qualifying expenditure incurred in relation to a cluster area on or after 3 December 2014. The definition of qualifying expenditure is the same as for Investment Allowance. Once an area has been determined as a cluster area by OGA all subsequent qualifying capex will qualify for the allowance. The benefit of cluster allowance over investment allowance is that income from any of the interests included in the cluster will activate the allowance, not just income from the licence in question.
Onshore Allowance is designed to support the early development of onshore oil and gas projects including shale gas developments. The allowance is available in respect of capital expenditure incurred on and after 5 December 2013 in relation to an onshore oil and gas related activity, and is calculated at a rate of 75% of a qualifying capex spend, reducing adjusted ring fence profits subject to supplementary charge once activated. The qualifying expenditure is the capital expenditure incurred on a relevant site, which could be a field or a shale gas hub provided the site was authorised for development after 5 December 2013 and is not expected to produce more than 7m tonnes of production. The extension of qualifying costs to include certain operating and leasing costs does not apply to the onshore allowance. If the allowance cannot be activated (due to a lack of production income from the site) it can be transferred to another site three years after the expenditure was incurred.
DECOMMISSIONING RELIEF DEEDS
Provisions under which the Government will guarantee tax (CT, SC and PRT) relief for certain decommissioning expenditure were introduced in FA 2013. This is achieved by the oil company or its affiliate entering into a decommissioning relief deed (DRD) with Government. The DRD will guarantee the level of tax relief (other than the rate) which would have been obtained if the decommissioning expenditure had been incurred at the date of the FA 2013 receiving Royal Assent if there has been a change of law, and guarantees the relief that will be available if one party has to pick up the costs due to the default of another (unconnected) party. It is thought that entering into a DRD will allow security for decommissioning to be provided on a net of tax basis.
The final version of the DRD is available on the HM Treasury website together with guidance on how to apply for one.
CW Energy LLP – November 2016