Abstract Background/Introduction Heart failure with preserved ejection fraction (HFpEF) remains underdiagnosed in low-middle income countries including India. The simple and validated H2FPEF score has largely replaced the diagnostic need for invasive right heart catheterization. The score has therapeutic implications by stratifying patients into low, intermediate and high-risk groups. The relevance of this score is yet to be ascertained in the Indian population. Purpose We hypothesized that the H2FPEF score may fall short in accurately predicting HFpEF in our population, thus warranting a new score. Methods We conducted a prospective observational study over one year at the out-patient department of a tertiary-care hospital in India. Patients presenting with clinical features of heart failure were screened and enrolled in the study. Demographic, clinical, laboratory and echocardiographic details were recorded by the principal investigator using an online data collection tool. Patients were stratified into ‘low risk’, ‘intermediate risk’ and ‘high risk’ probabilities, with respective cut-off values of 0-3, 4-6, and 7-9 using the point-based score, and <30%, 30-59%, and >60% via the continuous model of H2FPEF score. Pearson’s chi-square test identified significant risk factors that were purposed into a novel AB-HFPEF score. Cohen’s kappa correlation determined the degree of agreement in the risk stratifications of the H2FPEF and the AB-HFPEF score, using the continuous scoring model as the reference. Results Among the 189 patients screened, 137 were enrolled in the study. The baseline characteristics are recorded in Table 1. Pedal edema and uncontrolled hypertension were noteworthy risk factors. A novel AB-HFPEF score was subsequently designed and scored as follows: Age (> 60 years) - 1, BMI (> 30 kg/m2) - 2, uncontrolled Hypertension (>140/90 mmHg) - 1, Filling pressure (E/e' > 9) - 1, Pulmonary Artery Systolic Pressure (> 35 mmHg) - 1, pedal Edema - 1, atrial Fibrillation - 3. Receiver operating characteristics (ROC) curve analysis demonstrated an area under the ROC curve (AUC) of 0.85 (95%CI, 0.78 to 0.91) for ‘low risk’ strata and 0.87 (95%CI, 0.81 to 0.93) for ‘high risk’ strata. The optimal stratification was 0-2, 3-4, and 5-10 points for the ‘low risk’, ‘intermediate risk’, and ‘high risk’ respectively. There was a moderate agreement of the AB-HFPEF score with the reference score (κ = 0.48 (95% CI, 0.36 to 0.60), p < 0.001), while the point-based H2FPEF score had only a slight agreement (κ = 0.15 (95% CI, 0.05 to 0.25), p < 0.001), as illustrated in Figure 1. Conclusion(s) The novel AB-HFPEF score performs better risk stratification in Indian patients with HFpEF as compared to the point-based H2FPEF score. We hence propose the AB-HFPEF score as an instrument for tailored cardiology care in the Indian demographic, laying the cornerstone for larger validation and prognostication studies.Table 1:Baseline characteristicsFigure 1:Heat Map Illustration

Background and Aims: It is estimated that approximately 25% of the Indian population has elevated Lp(a). In India Acute coronary syndrome (ACS) occurs in young population. But the prevalence of elevated Lp(a) among ACS patients is not known. The aim of this study is to evaluate the prevalence of Lp(a) in ACS and to find the association between elevated Lp(a) levels and severity of disease. The study will also evaluate the prevalence of elevated Lp(a) among Familial hypercholesterolemia (FH) in ACS patients. Methods: All ACS patients (n = 1021) were studied for Lp(a) levels, coronary angiography and screened for FH by DUTCH clinical lipid network criteria. Lp(a) levels of > 50mg/dl was considered as elevated. Gensini score more than 35 was considered to be associated with severe CAD. Correlations between Lp(a) levels and Gensini score was examined using Spearman correlation analysis. Results: 34 % of ACS patients exhibited elevated Lp(a) levels. 37% of young ACS patients, exhibited elevated Lp(a) compared to 32% elderly patients. Elevated Lp(a) was observed in 40% patients with multivessel disease compared to 26% patients who had single vessel disease . 43% of FH patients had elevated Lp(a) There was significant, positive correlation of Lp(a) levels with Gensini score (p = 0.002) Conclusions: Lp(a) was higher in young ACS patients. Patients with elevated Lp(a) exhibited severe disease angiographically based on Gensini score. Elevated Lp(a) was more common in FH suggesting it to be independent factor for accelerating the disease.

This paper reports on a case study of the community group Zero Emissions Noosa, whose goal is for 100% renewable electricity in the Noosa Shire (Queensland, Australia) by 2026. Described within this paper are the processes used by Zero Emissions Noosa to set up their zero emissions plan, involving community engagement and the use of an external consultant. The external consultant was employed to produce a detailed report outlining how to successfully achieve zero emissions from electricity in the Noosa Shire by 2026. This paper explains how and why the community engagement process used to produce the report was just as important as the outcomes of the report itself. Modeling was undertaken, and both detailed and contextual information was provided. Inclusion of the community in developing the scenario parameters for the modeling had a number of benefits including establishing the context within which their actions would occur and focusing their efforts on options that were technically feasible, financially viable and within their capabilities to implement. This provided a focal point for the community in calling meetings and contacting stakeholders. Rather than prescribing a particular course of action, it also resulted in a toolbox of options, a range of possible solutions that is flexible enough to fit into whatever actions are preferred by the community. The approach and outcomes discussed in this paper should, therefore, be useful to other communities with similar carbon emission reduction goals.

Increasingly, there are calls for the owners of photovoltaic (PV) systems to pay additional charges on the basis that they are not contributing their fair share to network revenue. Air conditioners (A/Cs) are even more widespread than distributed PV systems, and their use has increased demand peaks and the size of networks required to meet them, the cost of which is typically recovered from all customers. There appears to be limited analysis in the literature regarding the impacts of A/C and PV on the electricity bills of customers who do not have these technologies. While the impacts of renewable energy on centralised electricity generation have been explored in the literature, this paper proposes a methodology to estimate the financial impacts of PV and A/C that flow through network operators to other customers. The analysis indicates that, in the datasets used, A/C systems have most likely resulted in significant bill increases for customers who don’t have them. In contrast, PV systems have most likely had a minimal financial impact on customers who do not have them. While these analyses were undertaken using Australian data, the method is applicable to most countries with modifications to suit the local regulatory environment.

Australia has likely the world's highest residential photovoltaic (PV) system penetration. In this paper, the impact of distributed PV on peak demand at different distribution network zone substations (ZSs) is assessed by upscaling 15 min PV generation data from 270 distributed PV systems across Sydney, Australia, and comparing it with load data from 138 ZS serving the Sydney region. Gross load (load had there been no PV) was estimated, allowing the impact of current and higher PV penetrations on the value and time of peak at the different ZSs to be assessed. A probabilistic assessment of the impact of PV on ZSs is conducted, based on the availability of PV during the peak demand periods. To better understand the impact of PV on peak demand, K-means clustering is used to group ZSs based on PV generation during peak periods as the clustering features. Mapping of PV availability across percentage of peak times for all ZSs highlights the interannual variability of peak reductions and the potential impact of short-term load shifting. The impact of different penetration levels of distributed PV on the peak demand of the entire distribution network is also assessed by aggregating the ZS loads.

There is growing policy and regulatory interest in better aligning electricity tariffs with the cost of providing network services to customers: to provide a better price signal for economically efficient use of the network, and reduce cross subsidies between different customers. Given that network costs are significantly driven by peak capacity requirements, many proposals for more cost-reflective tariffs include a demand (capacity) component. However, there are many complexities in the implementation of such tariffs. This paper first presents a method to visually assess how cost-reflective a particular demand charge network tariffs is. We apply it to a typical demand charge network tariff proposal within the Australian National Electricity Market and actual consumption data of 3876 Sydney households, and find it to have low cost-reflectivity in terms of aligning customer bills with their contribution towards network peak demand. Such misalignment has potentially significant adverse impacts on the economic efficiency of such tariffs – an issue that does not appear to have received sufficient policy attention. We then use this assessment method to demonstrate how a demand charge tariff structure can be adjusted to make it significantly more cost-reflective. This method can be applied to any tariff that includes a capacity-based component.

Local electricity sharing schemes have the potential to play an increased role in the Australian National Electricity Market as the penetration of distributed energy resources (DERs) continues to grow. These models allow participants to share energy between separately owned and operated DERs, however are largely untested. While embedded networks have generally been established for specific circumstances such as shopping centres and airports, there is growing interest in their wider application in providing a framework for local sharing of energy resources. However, the potential operational and commercial implications for key stakeholders (including consumers, network operators and retailers) are not well understood. An example of one such proposal is within the Byron Arts and Industrial Estate through which the community owned retailer, Enova, is seeking to offer a bespoke energy solution to its customers within the estate. In this paper, a new open source software model for assessing technical and commercial outcomes of local electricity sharing is presented. The model is applied to the Byron Arts and Industrial Estate case study which demonstrates the relevance of modelling to support appropriate investment and operational decision-making.

Network tariffs in the Australian National Electricity Market (NEM) have received growing attention in recent years as the main contributor to rapidly rising electricity bills for residential and small business customers. A number of government enquiries in 2012 and 2013 found significant overspending by networks, and a need to review regulations that had encouraged network over-investment in order to expand their regulated asset base. In response, the Australian Energy Market Commission (AEMC) has introduced a rule change that requires Distribution Network Service Providers (DNSPs) to implement tariffs that better reflect the cost of providing network services to customers. The aim is to achieve more economically efficient use of the network by pricing the network service correctly and hence driving more appropriate end-user levels and patterns of electricity demand. The rule specifies that tariffs must now be based on the long run marginal cost (LRMC) of providing additional network capacity and that the residual costs (the sunk network costs) should be recovered in a way that does not distort the LRMC price signal. There is, however, a lack of clarity in the rule about how the LRMC-based tariffs should be calculated and how the residual costs should be recovered. This paper presents the outcomes of a study that assesses the cost-reflectiveness of network tariffs proposed under the new rule by Australian DNSPs, as well as tariffs put forward by other stakeholders. The study uses load data from 300 households located in one of the DNSP areas. The tariffs are assessed against a range of design criteria, including the extent to which they reflect the LRMC of the network and account for geographical differences, and the extent to which the pass-through of residual costs distorts the ‘efficient’ pricing signal provided by the LRMC. The study also considers the extent of cross subsidisation between customers under each of the assessed tariffs, and how this varies for different locations in the network with different LRMCs. Developing cost-reflective tariff structures is a highly complex process and the proposed solutions may not be ideal. This study finds that the demand charge-based tariffs proposed thus far may not be more cost reflective than current pricing structures. If a transition is made towards implementing demand charge-based tariffs, more attention needs to be placed on their design, and greater consideration of spatial variation in network conditions is required to minimise cross subsidies and maximise cost-reflectivity.

Pacific Islands are at the forefront of the trend towards high or even 100% renewable energy penetration of their electricity grids. Many have been highly or totally reliant on imported diesel fuel, with associated price uncertainties and GDP impacts. Countries like Fiji are highly reliant on hydro power and become vulnerable in periods of low rainfall, such as during El Nino events, when diesel use increases. All Pacific Islands are prone to cyclones, making technology choice and installation requirements harder. In addition, transport of equipment, installation and maintenance can be extremely challenging, and further limit feasible options. Renewable energy-based electricity has the potential to improve the quality of life in many remote islands and also to stabilise power costs across the region. Many Pacific Island countries have introduced renewable energy targets or support policies and some, such as Tokelau, have successfully moved to 100% renewable supply, with a PV/battery system. Policy approaches across the region vary and are often complicated by reliance on aid funding, which in turn has its own drivers. In this paper we propose criteria for assessing the viability of renewable energy support programs, discuss some options suitable for use in Pacific Islands and examine the implications for electricity tariff setting.

Solar Photovoltaic (PV) system installations are enjoying a continued and remarkable growth in Australia. Currently there are over a million PV systems installed in the country with an installed capacity of over 3.5GW, the majority of which are small grid-connected rooftop systems of less than 10kW capacity. Australian conditions can be very harsh, contributing to early equipment failure rates, while installation of small systems can be suboptimal,and often without monitoring. Documentation of faults with PV products and installations in Australia is limited and there is little publically available information in regards to the types of problems that occur, where and why they occur, how frequently and if they are an ongoing issue. The reliability of PV systems is a strong determinant of cost effectiveness, and critical to continued investor confidence. A ‘PV Module and System Fault Reporting Portal’ (PVFRP) has been developed to increase the understanding of the PV industry and other stakeholders about the types of problems that are found with different system components in the Australian environment. The PVFRP contains a survey to collect data from owners, operators, installers and inspectors of PV system who have detected a fault/problem with whole or part of a system. Analysis and dissemination of the Portal data will help to improve future PV system design, component selection, product development and product approvals for Australian conditions. The survey is available at: www.surveymonkey.com/s/pvwebportal. This paper presents the initial findings of the survey after five months of operation. The number of responses received thus far is not large enough to reach to any substantive conclusions, however, they are in agreement with the research outputs achieved elsewhere. This information will help the industry address the challenges that PV systems, components and related service delivery are facing in Australia. The information presented here will be updated as more data become available and will be published on a regular basis.

Policy measures that establish a trading market in ‘energy savings’, going under names including White Certificates, Energy Efficiency Targets, Energy Savings Schemes and Energy Efficiency Certificate Trading, are receiving growing policy attention and have been implemented in jurisdictions including Europe, the United States and Australia. They are often portrayed as a market-based energy efficiency solution to energy ‘market failure.’ This paper highlights some key challenges with such ‘designer’ markets that attempt to commodify a potentially wide range of ‘energy savings’ activities and then facilitate the financialisation of such opportunities through tradable instruments. A key challenge is that energy efficiency opportunities are highly heterogeneous, and exist within a broader energy services decision making context. Hence the genuine additionality of energy savings is generally difficult to measure and verify. This, in turn, poses particular challenges and risks when establishing financial instruments and associated markets to trade complex, interacting, uncertain and highly

In Australia, as electricity prices have increased, driven mainly by increases in peak demand, electricity use has decreased every year since 2008/09. The factors most responsible for these decreases include increased electricity costs, energy efficiency, solar water heaters and photovoltaics. Further increases in electricity prices and uptake of these technologies could result in further reductions in demand. This combined with the projected increases in peak demand and associated expenditure could put further pressure on utilities’ traditional revenue and business models, especially those of networks. Government responses to date to minimise electricity costs will most likely be ineffectual and are inconsistent with absolute reductions in electricity use. This is due to the limited attention given to alternatives to the Network Determination process used to establish future network expenditure, the lack of practical suggestions for decoupling network operators’ revenue from electricity use, and the treatment of distributed energy (energy efficiency, demand management and distributed generation) as an ‘add-on’ to the existing market. We propose the use of Integrated Resource Planning to ensure that distributed energy competes equally with network augmentation, and regulation of distribution network operators under a revenue cap and Overs and Unders process to decouple their revenue from electricity use, both in the context of a broader distributed energy market. We describe how all these arrangements can be integrated in such a way that results in competition between supply-side and demand-side options at all levels: generation, networks and retail. We also provide examples of the types of policies needed for this to occur, as well as the most important issues that would need to be addressed. The issues and approaches discussed here should be relevant to any country facing ongoing reductions in electricity use or high penetrations of distributed generation.

The global climate policy environment is currently characterised by a small number of national or regional ‘flagship’ emissions trading schemes and a very large number of smaller more targeted ‘flotilla’ policies. We use an assessment framework to identify the characteristics of policies that affect their likelihood of introduction and alteration during the policy development process. We conclude that this mix of flagship and flotilla policies is at least in part an inevitable consequence of incumbent stakeholder pressure that results in flagship policies being blocked or weakened by those opposing action, and if weakened sufficiently, possibly blocked by those seeking stronger action. In contrast, smaller flotilla policies can be designed to have less impact on large incumbents and/or be of benefit to a different group of stakeholders who then provide political support. As a result, flotilla policies are likely to remain as key elements of the climate policy mix, to reduce emissions beyond those achieved by flagship policies, and to reduce emissions where no flagship policies exist. These findings have two consequences for policy design: the need to ensure that flagship policies do not reduce the effectiveness of flotilla policies, and that flagship policies are capable of being enhanced over time.

Distributed generation is being deployed at increasing levels of penetration on electricity grids worldwide. It can have positive impacts on the network, but also negative impacts if integration is not properly managed. This is especially true of photovoltaics, in part because it's output fluctuates significantly and in part because it is being rapidly deployed in many countries. Potential positive impacts on grid operation can include reduced network flows and hence reduced losses and voltage drops. Potential negative impacts at high penetrations include voltage fluctuations, voltage rise and reverse power flow, power fluctuations, power factor changes, frequency regulation and harmonics, unintentional islanding, fault currents and grounding issues. This paper firstly reviews each of these impacts in detail, along with the current technical approaches available to address them. The second section of this paper discusses key non-technical factors, such as appropriate policies and institutional frameworks, which are essential to effectively coordinate the development and deployment of the different technical solutions most appropriate for particular jurisdictions. These frameworks will be different for different jurisdictions, and so no single approach will be appropriate worldwide.

Although public energy efficiency policy is ultimately set by government, it arises via a complex social process involving interactions between potentially numerous different groups. The final policy design is altered according to the aims of the various groups involved and how well each manages to influence the process. Governments can employ various strategies to navigate this process, one of which is the choice and detailed design of the policy instrument itself. This paper presents a framework that aims to identify the characteristics of energy efficiency policies that affect firstly their likelihood of introduction, and then their robustness against adverse changes during the policy development process. We apply this framework to eight different Australian energy efficiency policies that can be divided into three different types: Support mechanisms (Energy Efficiency Opportunities and the Australian Carbon Trust Energy Efficiency Program); Command and control (Minimum Energy Performance Standards and the Building Sustainability Index); and Price-based mechanisms (New South Wales (NSW) Home Saver Rebates and three State-based white certificate schemes). This assessment can help explain why some types of energy efficiency policies are implemented and are more effective than others. It may therefore provide guidance not only regarding the types of policies that governments could favour, but how to design them so they are more likely to be effective after emerging from the policy development process.