zilongwang/ReadingBank huggingface dataset:
Aero Review Review Date Function / Phase Relocation Assistance – Residential Displacement, cont. Moving Payment: Date Claimed: Amount: $ Date Paid: Amount: $ Moving Payment Type: Schedule (# of rooms) Actual Cost: $ Moving Payments Acceptable? *Date Corrective Action Completed (see Remarks) Relocation Assistance – Business, Farm, NPO Displacee Name: Occupancy: Owner Tenant Replacement Site Address: Relocation Agent: Initial Interview Date: Brochure Given? Relocation Services Offered? Accepted? Date Eligibility Notice: RHP Offer Date: Notice to Vacate Date: Move Date: Inventory Date: Update: Update: Moving Bid Date: #1 #2 #3 Amount $ $ $ Self Move Eligibility: Amount $ Date: Moving Expense Claim: Date Amount $ $ $ Moving Expense Paid: Date Amount $ $ $ Searching Expense Paid: $ Reestablishment Expense Paid: $ Fixed Payment (in lieu) Amount: $ Moving Expense Payments Acceptable: *Date Corrective Action Completed (see Remarks) Remarks:
Moving Expenses Worksheet – Residential (49 CFR 24.301) Airport: Project: Sponsor: Parcel: County: Unit: Claimant Name: 1. Type of Payment claimed: Fixed payment $ Reimbursement of Actual Expense (complete item 2 including any storage cost) Supplementary Claim for Storage Cost (complete item 3) 2. Actual Moving Expenses (See below for Eligible and Non-eligible Expense) Amount Claimed For Agency Use Only a. Moving Costs b. Transportation Costs - Families and Individuals (if any) c. Cost of Insurance (Move and Storage) d. Storage Costs (complete item 3) e. Other: (explain under Remarks below) Total Amount Claimed $0.00 $0.00 Less Amount of Advanced Payments (if any) Total Amount Due $0.00 $0.00 3. Storage Cost (complete only if personal property was moved to and from storage) Type of Claim: Initial Supplemental Final Date Property Moved Date Property Moved Storage Location: with Mover other location TO Storage: FROM Storage: Eligible Moving Expenses The actual, reasonable, and necessary expense for: Transportation of individuals, families, and personal property from the acquired site to the replacement site not to exceed a distance of 50 miles, (unless the 50 mile limit is waived for cause by the agency). Packing and unpacking, crating and uncrating of personal property. Disconnecting, dismantling, removing, reassembling, and reinstalling relocated household appliances, and other personal property. Storage of personal property as necessary intransit up to 12 months, (unless extended by the agency if necessary). Insurance for the replacement value of the property moved and/or stored. The replacement value of property lost, stolen, or damaged in the move, not through the fault or negligence of the displaced person, or his/her agent or employee; where insurance coverage for such items is not available at reasonable cost. Ineligible Expenses Cost of moving structures or other real property improvements. Interest on a loan of funds for moving costs. Additional expense because of living in a new location. Personal injury. Any legal fee or other cost for preparing a claim for a relocation payment or for representing the claimant before the agency. Expense to search for a replacement residence. Improvement to the replacement real property. Remarks:
[ MIDP Computation Using TI Business Analysts or Radio Shack EC-100 Airport: Project: Sponsor: Parcel: County: Unit: Old Mortgage: New Mortgage: Balance Amount Interest Rate Interest Rate Monthly Payment Points Term Turn calculator on ON Put calculator in Financial Mode 2nd Mode Explanation Key Entry Result 1. Remaining Term of Old Mortgage Enter remaining balance $ Enter old interest rate Convert to monthly = Store in %i Enter old monthly payment $ Compute remaining term of old mortgage 2nd N 2. MIDP Calculation Enter new interest rate Convert to monthly = Store in %i Enter remaining term of old mortgage n Enter monthly payment of old mortgage PMT $ Compute new mortgage $ Compute points x = $ Difference of old mortgage - new mortgage = $ Add amount of points computed above + $ MIDP = $ 1 2 2 2 1
Hot Mix Asphalt (HMA) Paving Daily Record Date: Airport: IL Project No.: Mix Design No.: Pay Item No., Description, Pay Unit: Name: Contractor: Resident Engineer Resident Technician Paving Location: Inspectors/Visitors: Process Control Weather Time Temp. Conditions Notes Equipment Manufacturer/Model Tach Check or Tire Pressure Amplitude Setting Paver Reed Tach Mat’l Transfer Device Breakdown Roller Reed Tach High Med Lo Vibratory Roller Reed Tach High Med Lo Pneumatic Roller Tire Pressure Finish Roller Max. Vib. Roller Speed VPM = ft./min Max. Paver Speed ft/min X .9 = ft/min impacts/foot passes Paving Check Time Temp. in Truck Temp. Behind Paver Paver Speed Independent Weight Check Needed Today: Yes No Scale Decal Number: Total Running Yield Checks Starting Station: Time Total Tons Placed Check Station Length Placed (1) Theo. Tons (2) Yield % (3) Time Total Tons Placed Check Station Length Placed (1) Theo. Tons (2) Yield % (3) Length Placed = Starting Station – Check Station Theo. Tons = (Length x Mat Width x Lbs./Sq. Yd. X Mat Thickness) + (9 x 2000) Yield % = (Total Tons Placed Theo. Tons) x 100
Yes No N/A 6. Payments to the contractor for this pay period were made in compliance with contract provisions as follows: Payments are verified by the Sponsor’s internal audit of contract records kept by the Resident Engineer, and If appropriate, pay reduction factors required by the specifications are applied in computing this payment and a summary of pay reductions made available to the FAA/IDA upon request. 7. The project will be accomplished without significant deviations, changes, or modifications from the approved plans and specifications, except where approval is obtained from the FAA/IDA. I certify, for the project identified herein, responses to the forgoing items are accurate as marked and have prepared documentation attached hereto for any item marked “no” that is correct and complete. Name of Sponsor Signature of Sponsor’s Designated Official Representative Typed Name of Sponsor’s Designated Official Representative Typed Title of Sponsor’s Designated Official Representative Date *This form was adapted by the Illinois Department of Transportation’s Division of Aeronautics from the U.S. Department of Transportation’s Federal Aviation Administration.
FIELD INSPECTION STAFF RESUME Consultant Airport Construction Inspection Personnel Plan Continued Page of IL Project #: Candidate Name: Printed Name Signature ( ) Email Address Mobile Phone Number Consulting Firm: Education: List highest level completed: Date graduation: Documentation of Contract Quantities Certificate #: Expiration Date: Professional Engineer License #: Experience and Other Qualifications/Training of the named applicant to provide construction inspection The below section is for changes to the original approved plan, the project manager shall certify below: This change is submitted in accordance with the certification as provided on the original plan. The candidate’s project role and qualifications are marked in the boxes to the right. Inspection Role QC/QA HMA3 QC/QA PCC4 IDOT Doc Class Current5 Licensed PE6 NPDES7 IDA RE Class8 RE1 Project Manager Signature Date 1,2,3,4,5,6,7,8 See last page for instructions
Better Regulation Update – November 2013 Recap October & November Rate of return: held stakeholder forum and published issues paper on equity beta for consultation. Consumer reference group: held CRG meeting on 17 October. Consumer engagement: published final 6 November. Confidentiality: published final guideline 19 November. Upcoming November & December Rate of return: publish final guideline in mid-December. Shared assets: publish final guideline on 29 November. Expenditure assessments: publish final guideline on 29 November. Expenditure incentives: publish final guideline on 29 November. This is our final newsletter update for the Better Regulation program. We would like to thank all stakeholders for their active involvement in the large amount of work done this year on reforming network regulation. We published our final consumer engagement guideline for network service providers on 6 November, and our final confidentiality guideline on 19 November. We will publish the final expenditure assessment, expenditure incentives and shared assets guidelines on 29 November. We expect to publish the final rate of return guideline in mid-December. The impact of our guidelines is the subject of this month’s spotlight. We will be publishing two more documents to round out the Better Regulation program. The first will be a report on the consumer reference group. It will feature our summary of how the group worked and assessment of how effective it was. The second will be the last in our series of policy notes which explain the reform package as a whole. It will follow on from Better Regulation: an integrated package and the Better Regulation: reform package update. These documents will all be available on our website. Spotlight: Applying Better Regulation The Better Regulation guidelines will apply to network businesses at their next determination. Network prices will first begin to be affected by our new approach in NSW and the ACT. Determinations for these businesses will commence in early 2014 and be finalised in 2015. Following NSW and the ACT, we will implement the Better Regulation reforms in Queensland, SA and then Victoria. All energy networks will be subject to the new approach by 2018. Some of our reforms are already having an effect before our next determinations. We are already collecting data from network businesses to support our new forecasting and benchmarking techniques. For the majority of businesses from next year onwards any capital investments they make will be subject to our ex post review process.
Attachment 1 - Confidentiality template Title, page and paragraph number of document containing the confidential information Description of the confidential information. Topic the confidential information relates to (e.g. capex, opex, the rate of return etc.) Identify the recognised confidentiality category that the confidential information falls within. Provide a brief explanation of why the confidential information falls into the selected category. If information falls within ‘other’ please provide further details on why the information should be treated as confidential. Specify reasons supporting how and why detriment would be caused from disclosing the confidential information. Provide any reasons supporting why the identified detriment is not outweighed by the public benefit (especially public benefits such as the effect on the long term interests of consumers).
Attachment 2 - Proportion of confidential material Submission Title Number of pages of submission that include information subject to a claim of confidentiality Number of pages of submission that do not include information subject to a claim of confidentiality Total number of pages of submission Percentage of pages of submission that include information subject to a claim of confidentiality Percentage of pages of submission that do not include information subject to a claim of confidentiality Note: This notice is an approximate indication of the proportion and comparative proportion of material in [insert title of NSP's Regulatory Proposal] that is subject to a claim of confidentiality compared to that which is not.
Table 1. Scope and Coverage of the Confidentiality Guideline Element of the Confidentiality Guideline Context Binding/Not binding Relevant Provisions Stage one - discussions All Not binding - relevant consideration in using information disclosure powers N/A The manner in which NSPs must make confidentiality claims Regulatory Proposals (electricity) Binding NEL sections - 28, 28F NER clauses - 6.8.2, 6.14A, 6A.10.1, 6A.16A Access Arrangement Proposals and Information (gas) Binding National Gas Law (NGL) sections – 42, 48 Additions or amendments to Access Arrangement Proposals and Information (gas) Binding NGL sections - 42, 48 Responses to requests for information arising out of our gathering powers Binding NEL sections - 28, 28F NGL sections - 42, 48 NSP submissions on Regulatory Proposals (electricity), Access Arrangement Proposals and Information (gas) Binding NEL sections - 28, 28F NGL sections - 42, 48 Pass through applications Not binding - relevant consideration in using information disclosure powers N/A Pricing proposals Not binding - relevant consideration in N/A
using information disclosure powers Informal discussions and responses to informal requests for information Not binding - relevant consideration in using information disclosure powers N/A Stage two - information disclosure powers All Binding NEL sections - 28W-28ZB NGL sections - 324-329
Attachment 1 - Confidentiality template Title, page and paragraph number of document containing the confidential information Description of the confidential information. Topic the confidential information relates to (e.g. capex, opex, the rate of return etc.) Identify the recognised confidentiality category that the confidential information falls within. Provide a brief explanation of why the confidential information falls into the selected category. If information falls within ‘other’ please provide further details on why the information should be treated as confidential. Specify reasons supporting how and why detriment would be caused from disclosing the confidential information. Provide any reasons supporting why the identified detriment is not outweighed by the public benefit (especially public benefits such as the effect on the long term interests of consumers).
APPENDIX A.2 – AER REGULATORY DETERMINATION CALENDAR 2017 2018 2019 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 AusNet Services (electricity transmission) FD Powerlink, TasNetworks (distribution) DD* PC* FD Roma to Brisbane gas pipeline RP* DD* AGN (Albury), AGN (Vic), AusNet Services (gas), Multinet, GasNet RP* SUB* DD* FD* ElectraNet, Murraylink, TransGrid RP IP PF PC* Ausgrid, Endeavour, Essential, ActewAGL, TasNetworks N(T) N(A) N PP* FA DA FM RP PF Energex, Ergon, SAPN, Directlink N PP* DA FM RP PF * SUB RRP SUB CSUB
Background The Australian Energy Regulator is responsible for the economic regulation of covered natural gas distribution and transmission pipelines in all states and territories except Western Australia. Our functions and powers are set out in the National Gas Law (NGL) and the National Gas Rules (NGR). The carbon tax was repealed by the Australian parliament on 17 July 2014 and received royal assent the same day, removing APA’s carbon liability for 2014–15. As a result, APA no longer has an obligation to purchase and surrender carbon units as a liable entity under the Clean Energy Act 2011. Prior to the carbon tax repeal, APA had an obligation under the Clean Energy Act 2011 to purchase and surrender carbon units for each tonne of carbon pollution emitted as a liable entity operating a facility that exceeds a scope 1 (direct) emissions threshold of 25 000 tonnes of carbon dioxide equivalent. This liability relates to fugitive gas emissions from transmission and distribution pipelines and emissions from gas combustion in pipeline compressor stations.
submissions. We will make a final determination on the proposed Tariff Structure Statement in July 2016. What happens after a Tariff Structure Statement is approved? Once approved, a Tariff Structure Statement will remain in effect for the relevant regulatory period. The distributor must comply with the approved Tariff Structure Statement when setting prices annually for direct control services. We will separately assess the distributor's annual tariff proposals for the coming 12 months. Our assessment of annual tariff proposals will be consistent with the requirements of the relevant approved Tariff Structure Statement. An approved Tariff Structure Statement may only be amended within a regulatory period with our approval. We will approve an amendment if the distributor demonstrates that an event has occurred that was beyond its control and which it could not have foreseen so that the amended Tariff Structure Statement materially better complies with the distribution pricing principles. Victorian Government's authority to amend the National Electricity Rules or add further regulatory requirements The National Electricity Law (NEL) is contained in a Schedule to National Electricity (South Australia) Act 1996 and has been adopted by each of the participating jurisdictions in the National Electricity Market. This is done by State application statutes, which vary from state to state. In Victoria, the National Electricity (Victoria) Act 2005 (NEVA) applies the National Electricity Law and National Electricity Rules as Victorian legislation. However, under the NEVA, the Victorian Government can modify the NEL and the Rules by Ministerial Order. We are required to regulate applying the NEL and the Rules as they pertain to each particular jurisdiction. As explained above, we have received notification from the Victorian Minister for Energy and Resources of her intention to require Victorian distributors to implement changes to distribution network pricing arrangements by way of Ministerial Order. The AER may only approve a Tariff Structure Statement that complies with the Rules and all applicable regulatory instruments.
Table E3 Real material input cost escalation forecasts ($ real 2012-13) 2014–15 (%) 2015–16 (%) 2016–17 (%) 2017–18 (%) 2018–19 (%) Aluminium CEG SKM BIS Shrapnel Range (low to high) 4.2 4.69 1.4 1.4 to 4.69 5.8 4.88 5.6 4.88 to 5.8 5.0 3.09 3.9 3.09 to 5.0 4.2 4.42 11.0 4.2 to 11.0 3.6 2.97 -6.5 -6.5 to 3.6 Copper CEG SKM BIS Shrapnel Range (low to high) -0.9 -0.17 -0.9 -0.9 to 0.17 1.1 0.17 -1.5 -1.5 to 1.1 0.3 -1.15 0.3 -1.15 to 0.3 -0.3 -0.16 9.3 -0.3 to 9.3 -0.7 -1.45 -8.7 -8.7 to -0.7 Steel CEG SKM BIS Shrapnel1 Range (low to high) 0.6 2.84 5.1 0.6 to 5.1 3.2 2.45 1.0 1.0 to 3.2 0.6 -0.35 -0.2 -0.35 to 0.6 0.3 0.38 8.0 0.3 to 8.0 -0.1 -1.11 -8.9 -0.1 to -8.9 Oil CEG SKM BIS Shrapnel2 Range (low to -0.5 -5.11 1.4 2.8 -0.79 -1.1 2.6 0.74 -0.2 2.1 1.85 6.5 1.8 0.51 -6.2
Note This attachment forms part of the AER's draft decision on ActewAGL’s 2015–19 distribution determination. It should be read with other parts of the draft decision. The draft decision includes the following documents: Overview Attachment 1 – Annual revenue requirement Attachment 2 – Regulatory asset base Attachment 3 – Rate of return Attachment 4 – Value of imputation credits Attachment 5 – Regulatory depreciation Attachment 6 – Capital expenditure Attachment 7 – Operating expenditure Attachment 8 – Corporate income tax Attachment 9 – Efficiency benefit sharing scheme Attachment 10 – Capital expenditure sharing scheme Attachment 11 – Service target performance incentive scheme Attachment 12 – Demand management incentive scheme Attachment 13 – Classification of services Attachment 14 – Control mechanism Attachment 15 – Pass through events Attachment 16 – Alternative control services Attachment 17 – Negotiated services framework and criteria Attachment 18 – Connection methodology Attachment 19 – Pricing methodology
Overview of the Guideline This Guideline sets out the AER's approach to assessing and setting distribution expenditure forecasts, and the information we require to do so. Introduction The NER require DNSPs and the AER to engage on a DNSP's expenditure forecasting methodology to ensure that both the AER and the DNSP are aware, in advance, of the information the AER requires to assess the DNSP's proposal. To help facilitate this, we must set out the types of assessments we will undertake and the information we will require to do so. This Guideline indicates our likely assessment approach for capex and opex, the techniques we propose to use and the information we will require from DNSPs. Many of the techniques here and their associated data are common to expenditure assessments under the NER and our annual benchmarking reports. We must consider these benchmarking reports when assessing regulatory proposals. This Guideline focuses on expenditure assessment for standard control services. However, we also review expenditure forecasts for alternative control services. At the framework and approach stage, we will consider the assessment approach and techniques we will likely apply to alternative control services once we have formed a view on the likely classification of distribution services. We expect we will use the same techniques to assess both alternative control services and standard control services. Structure of the Guideline This Guideline sets out: our task and general assessment approach under the regulatory framework our assessment techniques our approach to assessing capex and opex the information we require for expenditure assessment. Transitional issues The NER require us to indicate how (if practicable) we will deal with transitional issues if a guideline indicates we may change our regulatory approach in future distribution determinations. While this Guideline indicates we may change our assessment approach in some ways, we do not consider transitional issues arise as a result.
Parties who assume control of a private network subject to an individual exemption must, within not more than 20 business days of commencing to own, operate or control that private network, make an application for exemption in the form set out in section 5 in Part C of this Guideline. Table 5 – Individual network exemption class Class Activity Registrable exemption Application for individual exemption NRI Specific exemption of a network not otherwise described All approved applications Detailed application required Note: Exemption class ‘NRI’ is ‘network registrable individual’ exemption and has no equivalent in the Exempt Selling Guidelines. It applies to exemptions to individuals made in accordance with clause 2.5.1 of the NER. From 1 January 2015 the AER will move to individual exemptions for retail selling. Allied to this we will review the conditions applicable to tables 1 and 3 of this guideline to determine whether those conditions should continue to apply post–2015. Our intention is to predefine the network element of the conditions to apply to each class of retail selling activity from 1 January 2015. If it is found that is not necessary to change the network conditions we will not do so. Consistent with this, we do not propose requiring an application for an individual network (as distinct from retail) exemption for network activities linked to retail selling post 1 January 2015, except where a variation of conditions is sought.
ND9 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable ND10 Not applicable Table 7 – Deemed classes of exemption – other situations Conditions Class 1 2 3 4 5 6 7 8 9 10 11 12 NDO1 Not applicable Not applicable Not applicable Not applicable NDO2 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable NDO3 Not applicable Not applicable Not applicable NDO4 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable NDO5 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable NDO6 4.2.1 4.2.1 Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable
Table 9 – Registrable classes of exemption – other situations Conditions Class 1 2 3 4 5 6 7 8 9 10 11 12 NRO1 Not applicable Not applicable Not applicable NRO2 Not applicable Not applicable Not applicable NRO3 Not applicable Not applicable Not applicable NRO4 Not applicable Not applicable NRO5 10 – Individual network exemption class Conditions 1 2 3 4 5 6 7 8 9 10 11 12 NRI
Other drivers of capex (such as replacement expenditure and connections works) may be recurrent. For such expenditure, we will attempt to identify trends in revealed volumes and costs as an indicator of forecast requirements. At the time of developing this guideline, capex is not currently subject to an incentive scheme like the EBSS. This means that although past actual expenditures and volumes may indicate a particular TNSP's likely future expenditure, we cannot presume it is efficient. The CESS may mitigate this issue to some extent. Consequently, and given the presence of non-recurrent expenditures, our assessment approach is typically more involved for capex than for opex. It may be necessary to review individual, or groups of, projects and programs to inform our opinion on total forecast capex (especially for TNSPs). Our approach for both opex and capex will place greater reliance on benchmarking techniques than we have in the past. We will, for example use benchmarking to assist us in determining the appropriateness of revealed costs. We will also benchmark TNSPs across standardised expenditure categories to compare relative efficiency. Assumptions Our general approach assumes that: the efficiency criterion and the prudence criterion in the NER are complementary past actual expenditure was sufficient to achieve the expenditure objectives in the past. Efficiency and prudence are complementary We consider that the notion of efficient costs complements the costs that a prudent operator would require to achieve the expenditure objectives. Prudent expenditure is that which reflects the best course of action, considering available alternatives. Efficient expenditure results in the lowest cost to consumers over the long term. That is, prudent and efficient expenditure reflects the lowest long term cost to consumers for the most appropriate investment or activity required to achieve the expenditure objectives. Past expenditure was at least sufficient to achieve objectives When we rely on past actual expenditure as an indication of required forecast expenditure, we assume that the past expenditure incurred by the TNSP was sufficient for it to achieve the expenditure objectives. That is, the TNSP’s past expenditure was the amount required to manage and operate its network at that time, in a manner that achieved the expenditure objectives.
Summary of submissions Issue Respondent View General Actew AGL The EBSS provides the incentive both to continually reduce costs to gain a share of benefits of doing so and to avoid unnecessary increases in costs due to the penalty incurred. APA Group Considers the current EBSS operates to incentivise businesses to remain within expenditure allowances, without sufficient attention to whether this represents an efficient outcome. CitiPower/Powercor/SA Power Networks The default position should be that incentive schemes are linked to revealed costs, except in exceptional circumstances. Support the current EBSS but suggest that where DNSPs are approaching the frontier they should be provided with a higher sharing ratio to encourage further pursuit of efficiencies that are harder and riskier to obtain. Council of Small Business Australia (COSBOA) Remain unconvinced that the current revealed cost approach to setting allowed opex, and the current EBSS are working as well as suggested in the Issues Paper. It is difficult to conclude unequivocally that the existing split for benefit sharing should be supported, although it has about the right intuitive feel. Energex Does not consider the available evidence demonstrates the existing revealed cost approach is deficient and isn't aware that a sufficiently robust exogenous method for determining base opex is open to the AER. For this reason supports the continued use of the current EBSS. Concerned that the incentive framework is becoming increasingly complicated and suggests the AER adopt a simple approach and not attempt to pursue false precision. Energy Networks Association (ENA) Supports the continued use of the EBSS. Has significant concerns around the proposed use of exogenous forecasting techniques. Considers that should the AER pursue such an avenue then we should explore how this can be accommodated through adjustments to the opex base year, whilst retaining the current EBSS rather than implementing a new EBSS
Figure 2: Average prices and total quantity – Gas supply hub ($/GJ, TJ) Moomba South East Queensland Wallumbilla Price Quantity Price Quantity Price Quantity 11 Jun - 17 Jun 2017 - - 7.40 154 7.92 184 % change from previous week - - 0 88 -1 -41 16-17 financial YTD - - 7.34 821 8.31 7623 % change from previous financial YTD - - - - 102 5 Figure 3 illustrates the daily prices in each gas market, as defined in figures 1 and 2. Figure 3: Daily gas market prices ($/GJ) Figure 4 compares average ancillary market payments (VGM) and balancing gas service payments (STTM) against historical averages. Figure 4: Average ancillary payments ($000) Victoria Ancillary Payments* Sydney MOS Adelaide MOS Brisbane MOS 11 Jun - 17 Jun 2017 - 54.31 9.24 1.79 % change from previous week - -7 29 -30 16-17 financial YTD 50.33 17.76 1.68 % change from previous financial YTD 82 60 8 * Ancillary payments reflect the compensation for any additional injections offered at a price higher than the market price. Note: only positive ancillary payments, reflecting system constraints will be shown here. More detailed analysis on the VGM is provided in section 1. Figure 5 shows the quantity and volume weighted prices of products traded in the Gas Supply Hub locations at Moomba, South East Queensland and Wallumbilla. Figure 5: Gas supply hub products traded for the current week ($/GJ, TJ) Moomba South East Queensland Wallumbilla* VWA price Quantity VWA price Quantity VWA price Quantity Balance of day - - 7.40 16.0 7.92 31.0 Daily - - 7.50 68.0 7.96 133.0 Day ahead - - 7.30 70.0 7.70 20.0 Weekly - - - - - -
% change from previous financial YTD 86 -1 83 2 66 2 96 1 Figure 2 sets out price and demand information is also shown for the voluntary Wallumbilla and Moomba Gas Supply Hubs (GSH). Figure : Average prices and total quantity – Gas supply hub ($/GJ, TJ) Moomba East Queensland Wallumbilla Price Quantity Price Quantity Quantity 23 Apr - 29 Apr 2017 - - 5.52 126 6.51 173 % change from previous week - - -37 306 -19 65 16-17 financial YTD - - 6.81 222 8.35 6817 % change from previous financial YTD - - - - 112 2 Figure 3 illustrates the daily prices in each gas market, as defined in figures 1 and 2. Figure : gas market prices ($/GJ) Figure 4 compares average ancillary market payments (VGM) and balancing gas service payments (STTM) against historical averages. Figure : Average ancillary payments ($000) Victoria Ancillary Payments* Sydney MOS Adelaide MOS Brisbane MOS 23 Apr - 29 Apr 2017 - 47.78 17.81 1.70 % change from previous week - 102 26 -12 16-17 financial YTD 48.68 19.62 1.69 % change from previous financial YTD 72 127 9 * Ancillary payments reflect the compensation costs for any additional injections offered at a price higher than the market price. Note: only positive ancillary payments, reflecting system constraints will be shown here. More detailed analysis on the VGM is provided in section 1. Figure 5 shows the quantity and volume weighted prices of products traded in the Gas Supply Hub locations at Moomba, South East Queensland and Wallumbilla. Figure : Gas supply hub products traded for the current week ($/GJ, TJ) Moomba East Queensland Wallumbilla*
Figure 2: Average prices and total quantity – Gas supply hub ($/GJ, TJ) Moomba South East Queensland Wallumbilla Quantity Quantity Price Quantity 26 Mar - 01 Apr 2017 - - 8.30 40 8.98 14 % change from previous week - - - - 5 -87 16-17 financial YTD - - 8.30 40 8.39 6462 % change from previous financial YTD - - - - 114 -1 Figure 3 illustrates the daily prices in each gas market, as defined in figures 1 and 2. Figure 3: Daily gas market prices ($/GJ) Figure 4 compares average ancillary market payments (VGM) and balancing gas service payments (STTM) against historical averages. Figure 4: Average ancillary payments ($000) Victoria Ancillary Payments* Sydney MOS Adelaide MOS Brisbane MOS 26 Mar - 01 Apr 2017 - 16.64 7.77 3.71 % change from previous week - -17 4 102 16-17 financial YTD 50.67 20.01 1.67 % change from previous financial YTD 69 140 7 * Ancillary payments reflect the compensation costs for any additional injections offered at a price higher than the market price. Note: only positive ancillary payments, reflecting system constraints will be shown here. More detailed analysis on the VGM is provided in section 1. Figure 5 shows the quantity and volume weighted prices of products traded in the Gas Supply Hub locations at Moomba, South East Queensland and Wallumbilla. Figure 5: Gas supply hub products traded for the current week ($/GJ, TJ) Moomba South East Queensland Wallumbilla* VWA price Quantity VWA price Quantity VWA price Quantity Balance of day - - - - 9.00 7.5 Daily - - 8.30 20.0 - - Day ahead - - 8.30 20.0 8.95 6.0 Weekly - - - - - -
3. Adelaide STTM The Adelaide STTM hub functions in the same way as the Sydney STTM hub. The same data that was presented for the Sydney hub is presented for the Adelaide hub in the figures below. ADL STTM daily ex ante and ex post prices and quantities Sun Mon Tue Wed Thu Fri Sat Ex ante price ($/GJ) 8.49 8.87 9.55 9.24 9.99 10.68 9.89 Ex ante quantity (TJ) 30 43 43 44 51 51 42 Ex post price ($/GJ) 8.45 8.50 9.24 9.51 9.66 10.01 9.89 Ex post quantity (TJ) 28 40 41 45 48 46 44 ADL daily hub offers and daily hub bids in price bands ($/GJ) ADL net scheduled and allocated gas hub supply (excluding MOS) ADL MOS allocations (TJ), service payments and commodity payments/charges ($000) 4. Brisbane STTM The Brisbane STTM hub functions in the same way as the Sydney STTM hub. The same data that was presented for the Sydney hub is presented for the Brisbane hub in the figures BRI STTM daily ex ante and ex post prices and quantities Sun Mon Tue Wed Thu Fri Sat Ex ante price ($/GJ) 7.31 7.56 9.12 9.11 8.06 9.00 8.66 Ex ante quantity (TJ) 68 83 87 84 91 84 69 Ex post price ($/GJ) 7.45 7.72 9.12 9.29 7.50 9.00 10.00
Ex ante price ($/GJ) 7.97 8.89 8.15 9.17 9.21 9.23 9.13 Ex ante quantity (TJ) 73 88 89 93 93 91 81 Ex post price ($/GJ) 7.42 8.89 8.33 9.19 9.21 9.99 9.63 Ex post quantity (TJ) 71 88 90 95 93 100 84 ADL daily hub offers and daily hub bids in price bands ($/GJ) ADL net scheduled and allocated gas hub supply (excluding MOS) ADL MOS allocations (TJ), service payments and commodity payments/charges ($000) 4. Brisbane STTM The Brisbane STTM hub functions in the same way as the Sydney STTM hub. The same data that was presented for the Sydney hub is presented for the Brisbane hub in the figures below. BRI STTM daily ex ante and ex post prices and quantities Sun Mon Tue Wed Thu Fri Sat Ex ante price ($/GJ) 7.00 6.37 7.19 7.51 7.20 8.00 6.33 Ex ante quantity (TJ) 76 92 94 94 93 85 74 Ex post price ($/GJ) 7.16 6.07 6.76 6.98 7.20 8.08 6.56 Ex post quantity (TJ) 76 90 91 91 93 87 79 BRI daily hub offers and daily hub bids in price bands ($/GJ) BRI net scheduled and allocated gas hub supply (excluding MOS)
Quantity Quantity Price Quantity 06 Aug - 12 Aug 2017 - - 6.33 144 - - % change from previous week - - -14 5 - - 17-18 financial YTD - - 6.90 919 7.69 622 % change from previous financial YTD - - - - -14 -80 Figure 3 illustrates the prices in each gas market, as defined in figures 1 and 2. Figure 3: Daily gas market prices ($/GJ) Figure 4 compares average ancillary market payments (VGM) and balancing gas service payments (STTM) against historical averages. Figure 4: Average ancillary payments ($000) Victoria Ancillary Payments* Sydney MOS Adelaide MOS Brisbane MOS 06 Aug - 12 Aug 2017 - 32.70 7.85 1.19 % change from previous week - -50 -32 11 17-18 financial YTD 60.98 8.43 1.68 % change from previous financial YTD -21 -44 8 * Ancillary payments reflect the compensation costs for any additional injections offered at a price higher than the market price. Note: only positive ancillary payments, reflecting system constraints will be shown here. More detailed analysis on the VGM is provided in section 1. Figure 5 shows the quantity and volume weighted prices of products traded in the Gas Supply Hub locations at Moomba, South East Queensland and Wallumbilla. Figure 5: Gas supply hub products traded for the current week ($/GJ, TJ) Moomba East Queensland Wallumbilla* VWA price Quantity VWA price Quantity VWA price Quantity Balance of day - - 6.29 50.0 - - Daily - - 6.43 22.0 - - Day ahead - - 6.28 30.0 - - Weekly - - 6.35 42.0 - - Monthly - - - - - -
Ex post price ($/GJ) 8.21 6.99 8.27 8.10 7.81 5.70 8.31 Ex post quantity (TJ) 40 53 57 55 51 34 41 ADL daily hub offers and daily hub bids in price bands ($/GJ) ADL net scheduled and allocated gas hub supply (excluding MOS) ADL MOS allocations (TJ), service payments and commodity payments/charges ($000) 4. Brisbane STTM The Brisbane STTM hub functions in the same way as the Sydney STTM hub. The same data that was presented for the Sydney hub is presented for the Brisbane hub in the figures below. BRI STTM daily ex ante and ex post prices and quantities Sun Mon Tue Wed Thu Fri Sat Ex ante price ($/GJ) 8.41 9.45 9.50 10.00 10.50 10.84 8.55 Ex ante quantity (TJ) 71 89 93 94 91 78 71 Ex post price ($/GJ) 9.45 9.50 9.50 10.50 8.50 8.22 8.56 Ex post quantity (TJ) 80 98 100 98 77 61 74 BRI daily hub offers and daily hub bids in price bands ($/GJ) BRI net scheduled and allocated gas hub supply (excluding MOS) BRI MOS allocations (TJ), service payments and commodity payments/charges ($000) 5. National Gas Bulletin Board
future meetings will be held monthly. However if there are matters that require input from members outside scheduled meetings, we will arrange for out-of-session meetings. The next steps: AER to circulate: a copy of letter from AER Chair Paula Conboy to the Prime Minister updating him on the various pieces of work being undertaken following the retailer roundtables (circulated on 15 December 2017) a copy of BETA’s draft report when it becomes available Attachment A ARG Attendees Organisation Name Australian Energy Regulator Sarah Proudfoot - General Manager, Retail Markets (Chair) ActewAGL Retail Kate Goatley - Manager, Business Projects Australian Energy Council Tess Fitzgerald - Retail Policy Manager Fiona Simon – General Manager, Strategy Brotherhood of St Laurence David Bryant - Research Officer Consumer Action Law Centre Zac Gillam - Senior Policy Officer Consumer Policy Research Centre Lauren Solomon – CEO EnergyAustralia Samantha Nunan - Industry Regulatory Lead, Corporate Energy Consumers Australia Sabiene Heindl - Director, Strategic Engagement Origin Energy Timothy Wilson - Manager, Regulatory Policy Powershop Michael Benveniste - Head of Commercial & Strategy Red Energy Ben Barnes – Regulatory Manager Uniting Communities/Uniting Care Mark Henley‎ - Manager Advocacy, Uniting Communities and Energy Advocate, Uniting Care Apologies Organisation Name Brotherhood of St Laurence Damian Sullivan - Research and Policy Senior Manager COTA Australia Robyn Robinson - Director Sue McGrath - National Policy Manager Non-member attendees Organisation Name
Powershop Michael Benveniste – Head of Commercial & Strategy Non-member attendees Organisation Name AER Rebecca Holland - Director, Retail Electricity Pricing Inquiry Department of the Environment and Energy (Cth) Clare Valence (Canberra) Essential Services Commission of Victoria Jodie McQueen (Melbourne)
8 Energy Definition of ‘regional office’ is extremely difficult. Arbitrary demarcation based on population/location will inadvertently capture depots with little prospect of competition. Recommend instead basing definition on offices servicing under 50,000 customers. ‘Regional office’ definition amended to 25,000 customer connection points within 100km radius. 9 Essential Energy A diagram would alleviate confusion around definitions of ‘other services’ and ‘other electricity services’. ‘Affiliated entity’ includes part of the DNSP providing ‘other distribution services’ and/or ‘other electricity services. This is confusing. Guideline requires direct control services to be separately branded from other distribution services. Should be able to provide distribution services under a single brand. Definition of regional office lacks clarity. Problems with population data. Definition would exclude many depots. Suggest using instead the number of customer premises linked to a depot—30,000 is equivalent to population of 50,000. Potential waivers from legal separation for other regulated business activities (e.g. water network business) is insufficient. Should be automatic exemption. Separate branding unworkable for regional offices where other office/staff separation obligations don’t apply. Separate branding should be exempted too. Waivers: AER should have 40 business days for waiver assessment require DNSPs to submit waiver renewal applications at least 8 months before end of existing reg period define interim waivers; if no waiver decision made when interim waivers expires, waiver should be granted automatically Guideline should allow 6 months for DNSP compliance following unsuccessful waiver application. Diagram provided in this Explanatory Statement. Agree. The Guideline uses a new term, ‘related electricity service provider’, to include a DNSP’s business units providing other distribution services. Distribution services that are not direct control services may be contestable. These should be functionally separated from provision of direct control services. ‘Regional office’ definition amended to 25,000 customer connection points within 100km radius. Expect limited number of waiver applications. Prefer having opportunity to consider the circumstances of a waiver application, rather than automatic exemptions. Agree. Separate branding is not required for regional offices. Waivers: Largely no change from Draft Guideline. This Explanatory Statement provides further guidance about our waiver processes. It is up to DNSPs to assess their circumstances and apply for waivers with appropriate lead time to manage their own compliance with the Guideline’s obligations.
NATIONAL ENERGY RETAIL LAW DIVISION 5 OF PART 6 AMENDED ROLR NOTICE The Australian Energy Regulator (AER) has issued this amended Notice under section 136 of the National Energy Retail Law (NERL). This RoLR notice replaces the notice issued by the AER on 4 April 2016. RoLR Event A Retailer of Last Resort (RoLR) event has occurred in relation to GoEnergy Pty Ltd (097 708 104) with the registered participant identification ‘216’ in the Short Term Trading Market (STTM). Prior to the issue of the RoLR notice dated 4 April 2016, Go Energy Pty Ltd was an authorised gas retailer for the purposes of Part 5 of the NERL with the authorisation identification TG12017. On 1 April 2016, GoEnergy Pty Ltd appointed an external administrator. The appointment of an administrator constitutes a RoLR event under section 122 of the NERL. The appointment of an administrator is also a default event in the gas Short Term Trading Market (STTM). On 4 April 2016, the Australian Energy Market Operator Limited suspended GoEnergy Pty Ltd from the Short Term Trading Market, with effect from 6:30am on Tuesday 5 April 2016 for the Sydney hub, and with effect from 8:00am on Tuesday 5 April 2016 for the Brisbane hub. The AER issued a RoLR notice on 4 April 2016. Amended RoLR notice On 13 April 2016, the AER amended the RoLR notice issued on 4 April 2016, to designate AGL Energy Sales & Marketing Limited as the default RoLR for customers connected to the gas distribution system of Jemena Gas Networks (NSW) Ltd (‘Jemena’). The RoLR notice dated 4 April 2016 designated AGL Retail Energy Limited for customers connected to Jemena’s gas distribution system. The RoLR notice was amended following the termination of AGL Retail Energy Limited’s registration as default RoLR for customers on Jemena’s gas distribution system and the appointment and registration of AGL Energy Sales & Marketing Limited as the default RoLR for customers connected to Jemena’s gas distribution system. These changes were necessary to ensure that the default RoLR for the affected customers is a participant in the Sydney hub of the gas Short Term Trading Market.
NATIONAL ENERGY RETAIL LAW DIVISION 5 OF PART 6 ROLR NOTICE The Australian Energy Regulator (AER) has issued this Notice under section 136 of the National Energy Retail Law (NERL). RoLR Event A Retailer of Last Resort (RoLR) event has occurred in relation to Urth Energy Pty Ltd (ABN 52 601 693 109) with the registered participant identification “URTH” in the National Electricity Market. Prior to the issue of this notice, Urth Energy Pty Ltd was an authorised electricity retailer for the purposes of Part 5 of the NERL with the authorisation identification E15003. On 1 February 2017, Urth Energy Pty Ltd appointed an external administrator. The appointment of an administrator constitutes a RoLR event under section 122 of the NERL. On 1 February 2017, the Australian Energy Market Operator (AEMO) suspended Urth Energy Pty Ltd from the National Electricity Market with effect from 24:00 hours Australian Eastern Standard Time on 1 February 2017. The suspension of a retailer’s right to acquire electricity from the wholesale market constitutes a RoLR event under section 122 of the NERL. Affected Fuels and Markets This Notice affects electricity customers in Queensland, New South Wales and South Australia who purchased electricity from Urth Energy Pty Ltd. Customers in other jurisdictions are not affected. Registered RoLRs Appointed as Designated RoLRs by operation of section 132(1) of the NERL Pursuant to section 132(1) of the NERL, the default RoLRs specified in Schedule 1 were taken to be appointed as the designated RoLRs for this RoLR event. Transfer date In accordance with section 140 of the NERL, customers of Urth Energy Pty Ltd will be deemed to have been transferred to the designated RoLR(s) set out in schedule 1 with effect from 24:00 Australian Eastern Standard Time on 1 February 2017. Revocation of Urth Energy Pty Ltd’s electricity retailer authorisation
9 Restring P1 bay conductor at Palmerston Substation - Waddamana-Palmerston No 2 110kV transmission circuit 50 0 50 10 Replace disconnectors, CT and bay conductor to achieve line rating increase and reduce market constraints - Sheffield-George Town 220 kV transmission line 1120 0 1120 11 Weather station telemetry renewal - Weather stations at Creek Road, Chapel Street, Devonport, Trevallyn, Hadspen, Sheffield, and Farrell substations 1050 0 1050 12 Upgrade of dead end fittings on selected transmission lines - No 1, Liapootah-Cluny-Repulse-Chapel Street No 1, Liapootah-Chapel Street No 2 and George Town-Comalco No 4 & 5 220 kV transmission circuits. Hadspen-Norwood No 1 & 2 110 kV transmission circuits. 840 0 840 13 Installation of second 220 kV bus coupler circuit breaker at Farrell Substation - Farrell Substation 665 120 785 14 Castle Forbes Bay Tee Switching Station disconnector upgrade - Castle Forbes Bay Tee Switching Station 250 0 250 15 Transmission line surge diverter installation and tower footing earthing improvements - Sheffield-Farrell 1 & 2, Farrell-Reece 1 & 2, Farrell-John Butters 220kV and Farrell-Rosebery-Queenstown 110 kV transmission circuits 550 550 16 Substandard spans verification and rectification – Multiple 3720 0 3720 Total 10,285 268 10,553 Source: AER analysis. Efficiency benefit sharing scheme parameters The AER determines that the efficiency benefit sharing scheme that applied to Transend in the current regulatory control period will apply in the transitional regulatory control period but modified to be in the terms of version 2 of the efficiency benefit sharing scheme as if the transitional regulatory control period was the first year of the subsequent regulatory control period. Application of the capital expenditure sharing scheme in the transitional regulatory control period The AER determines that no capital expenditure sharing scheme applies to Transend for the transitional regulatory control period. Application of the small-scale incentive scheme in the transitional regulatory control period The AER determines that no incentive scheme applies to Transend for the transitional regulatory control period. Pass through The AER determines that the "terrorism event" as defined in the Rules immediately prior to the date the National Electricity Amendment (Cost pass through arrangements for Network Service Providers) Rule 2012