Energy Software Development Services: Custom Software for Utilities, Oil and Gas, Renewables and the Grid

Updated October 2026 · Written and maintained by the Progression Agency strategy team

Energy software development services design, build and support the custom applications that utilities, oil and gas operators, renewable developers and grid-edge companies run on: meter data and outage tools, field crew apps, SCADA and historian integrations, distributed energy and EV charging platforms, energy management software and customer portals. This page is written for the operations, IT and OT leaders who buy that work, and it covers what gets built, the rules that shape it, how IT and OT integration is handled, what it costs and how to choose a vendor. Progression Agency is based in New York City and works with clients across the United States and worldwide.

What are energy software development services?

They are the design, engineering, testing and support of software made for one energy organization’s operations, data and regulators. The output is usually a layer that connects, extends or replaces part of the systems a utility or operator already runs, owned by the client rather than licensed.

Energy companies already buy a great deal of packaged software. A distribution utility runs a customer information system, a meter data management system, an outage management system and a GIS; a pipeline runs SCADA, leak detection and a work-management tool; a solar or storage owner runs plant controllers and a market-facing scheduling system. Energy sector software development is what fills the gaps between those products: the interface nobody sells, the field workflow the vendor never modeled, the report a regulator asks for that no dashboard produces, and the customer or partner portal that has to draw on four systems at once.

Who buys it

Investor-owned utilities, electric cooperatives and municipal utilities; gas distribution companies and pipeline operators; upstream producers and oilfield service firms; independent power producers, solar, wind and storage developers; EV charging networks; and the energy managers of large building portfolios and industrial plants. Each has a different mix of systems of record, rules and risk tolerance, which is why the sections below take the segments one at a time.

What it produces

Working software in the client’s own repositories and cloud accounts, with documentation, runbooks and the evidence an auditor will ask for: who can reach what, how releases are verified and how changes are recorded. A good energy software project also leaves a data model the organization understands, because the next project will reuse it.

What it is not

It is rarely a rewrite of a billing engine or a control system. Replacing a CIS or a SCADA master is a much larger program, normally run with the product vendor. Custom development earns its place around those systems, where the requirements are specific and the packaged roadmap will not reach them.

Energy sector software development, segment by segment

The work differs by segment because the systems of record, the regulators and the cost of a mistake differ. The table maps the usual starting point for each.

Electric utilities

Utility work clusters around the customer and the grid. On the customer side it means usage, billing and outage information that reaches people quickly; on the grid side it means getting meter, SCADA and asset data to the planners and dispatchers who need it, inside the security boundaries the utility’s CIP program sets.

Oil and gas

Pipeline and production companies live on time-series data from the field. Most custom work moves that data out of operational networks safely, puts it in front of engineers and compliance staff, and gives field crews tools that work where the signal does not.

Renewables, storage and the grid edge

Developers and owners need software that watches asset performance, tracks interconnection requests, forecasts output and bids into markets. Newer rules on aggregated distributed resources and line ratings have created software work that did not exist a few years ago.

Energy users

Large building owners and industrial plants buy energy software to measure, report and cut consumption. Their projects pull data from utility accounts, building automation and submeters into benchmarking and compliance reporting.

What a utility software company builds around CIS, MDM, OMS and GIS

A utility software company that does custom work rarely competes with the packaged systems; it connects them and builds the tools people use on top of them. These are the systems it meets most often and the work each one tends to generate.

Customer information and billing

The CIS holds accounts, rates and bills. Custom work around it includes self-service portals, payment and arrangement flows, contact-center tools that show a customer’s outage and usage history on one screen, and exports for rate-case analysis. The CIS stays the system of record; the custom layer reads from it and writes back through its supported interfaces.

Meter data management

Interval data from advanced meters lands in a meter data management system, which validates, estimates and edits it before billing. Analytics teams want that data for load research, theft detection, transformer loading and rate design; customer teams want it in portals. Custom pipelines that copy it into an analytics store without touching billing are a natural first project.

Outage management and restoration

Outage systems predict which device failed from customer calls and meter events, then guide crews. Custom work includes outage maps, text and email notifications, estimated restoration time feeds and after-action reports that combine outage, crew and weather data.

ADMS, DERMS and grid operations

Advanced distribution management and distributed energy resource management systems sit close to real-time operations. Custom software here is usually read-only analytics, planning tools and interfaces to market or aggregator systems, built to the utility’s security architecture rather than inside the control system itself.

GIS and asset records

Connectivity models in the GIS drive outage prediction and planning, so their quality matters. Field data-collection apps, validation tools that flag gaps between GIS and the field, and asset-history views for engineers are common custom builds.

Work and asset management

Inspections, vegetation management, meter exchanges and construction jobs move through a work and asset management system. Crews need mobile tools that match their actual steps, work offline and sync cleanly, which packaged mobile modules do not always manage.

Why meter data keeps growing, and what that means for software

Advanced meters now dominate US electric metering, so the data volume a utility’s software has to move, store and query has grown for a decade. The U.S. Energy Information Administration counts AMI meters on Form EIA-861 each year.

EIA’s advanced metering count by technology type shows AMI meters rising from 64.7 million in 2015 to 140.5 million in 2024, out of 168.1 million meters in total, while older automated meter reading (AMR) and standard meters fell. EIA defines AMI as meters that measure and record usage at least hourly and send the data to both the utility and the customer at least once a day. The detailed utility-level files are in the Form EIA-861 data files, whose 2025 final data was released on October 7, 2026.

What the volume means in practice

Hourly or 15-minute reads across hundreds of thousands of meters add up to billions of rows a year. Software that worked on monthly reads needs a different storage design, partitioned time-series tables or a columnar store, and queries written for it. Customer portals that show yesterday’s usage need caching and aggregation, not live queries against the meter data system.

Customer access to their own data

The Green Button initiative, which the Department of Energy describes as an industry-led response to a White House call to action, gives customers their usage in a consumer-friendly and computer-friendly format. Utilities that offer it need download and data-sharing features that are secure, consented and tested against the formats third-party apps expect.

Oil and gas software development company work: upstream, midstream and downstream

An oil and gas software development company spends most of its time on data: moving it from wells, compressors and pipelines to the people who decide, in formats the industry already shares, without opening the operational network to new risk.

Upstream: drilling, completions and production data

The industry exchanges well data in open formats maintained by Energistics: WITSML for drilling, completions and intervention, RESQML for the earth model and reservoir, PRODML for data from the reservoir-wellbore boundary to the custody transfer point, and the Energistics Transfer Protocol for real-time streaming. The OSDU Forum at The Open Group maintains the OSDU Data Platform, and the PPDM Association publishes the PPDM 3.9 data model and well identification standards. Custom software that reads and writes these formats is cheaper to connect and easier to replace.

Midstream: pipelines, control rooms and SCADA

Pipeline software lives next to control rooms. Federal rules for control room management, covered in the rules section below, reach the SCADA displays themselves, so any custom display, alarm or reporting work has to respect the operator’s procedures and verification steps.

Downstream and retail fuels

Terminals, distributors and retail fuel networks need inventory, delivery scheduling, pricing and driver tools. These are closer to logistics software than to grid software; our logistics software development page covers dispatch and proof-of-delivery work in depth.

Emissions monitoring and reporting

Emissions data comes from equipment counts, leak surveys, flare records and meters, and it ends up in regulatory reports. Federal requirements are moving: EPA proposed a reconsideration of the Greenhouse Gas Reporting Program in September 2025 that would remove obligations for most source categories, including the distribution segment of the petroleum and natural gas systems category, and suspend obligations for the remaining subpart W segments until reporting year 2034. EPA also extended the reporting deadline for 2025 data from March 31 to October 30, 2026. Software built for this area should keep calculation rules in configuration, not code, so a rule change is an update rather than a rebuild.

Field operations

Inspections, lockout and permit-to-work steps, equipment checks and incident reports can still run on paper or spreadsheets in field operations. Mobile apps that capture photos, readings and signatures offline, then sync to the work-management system, save crews time when they match the crew’s actual sequence.

Renewable energy software development for solar, wind and storage

Renewable energy software development covers the life of an asset: interconnection and permitting, construction, monitoring, forecasting, dispatch and market participation. The commercial edge often sits in the last three.

Asset performance monitoring

Plant data from inverters, trackers, turbines and battery systems flows into SCADA and historians. Owners want portfolio views that compare expected and actual output, flag underperforming strings or turbines and open a work order automatically. The hard part is rarely the dashboard; it is cleaning and aligning data from equipment made by different manufacturers.

Interconnection tracking

FERC’s Order No. 2023 reformed generator interconnection procedures to address queue backlogs, moving to a first-ready, first-served cluster study process; it took effect on November 6, 2023. Developers with dozens of projects in several queues need trackers for study phases, deposits, milestones and deadlines that link to their project documents.

Distributed resources and inverter standards

IEEE 1547-2018, an active IEEE standard, sets the technical requirements for interconnection and interoperability of distributed energy resources with the grid, and a revision project is under way. IEEE 2030.5-2023 defines the Smart Energy Profile application protocol used for demand response, load control, time-of-day pricing and management of distributed generation and electric vehicles. In California, the Public Utilities Commission opened a new Rule 21 rulemaking on August 20, 2025 to consider refinements to distributed energy interconnection. Software that talks to inverters has to follow these standards and the utility’s own implementation of them.

Storage dispatch and market bidding

Battery owners make money on timing. Dispatch software forecasts prices and state of charge, respects warranty limits and builds bids in the market operator’s formats. This is where custom logic tied to the owner’s own assets and contracts can beat a packaged optimizer.

Aggregated distributed resources

FERC’s Order No. 2222 requires regional transmission organizations and independent system operators to remove barriers to distributed energy resource aggregations in their capacity, energy and ancillary service markets. It took effect on December 21, 2020. Aggregators need software that enrolls customers, registers resources, forecasts and dispatches them, measures performance and settles with both the market and the customer.

Grid-edge, demand response and EV charging software

Grid-edge software coordinates devices the utility does not own: thermostats, batteries, chargers and building systems. Open protocols decide most of the architecture, and federal funding rules add hard requirements for public chargers.

Demand response signals

The OpenADR Alliance maintains the OpenADR 2.0 and 3.0 specifications and certifies products against them. Demand response platforms send events, receive opt-outs and telemetry, and settle performance; utilities and aggregators often need custom enrollment, notification and settlement layers around a certified core.

EV charging networks and NEVI rules

For stations funded under the National Electric Vehicle Infrastructure program, 23 CFR Part 680 requires chargers to conform to OCPP 1.6J or higher and, since February 28, 2024, to OCPP 2.0.1; charging networks to exchange data with other networks under OCPI 2.2.1; charger hardware capable of ISO 15118-2 and ISO 15118-20; and the ability to switch charging network providers without hardware changes. Each port must average more than 97% annual uptime, and states must report uptime and outage data. The Open Charge Alliance reports IEC approval of OCPP 2.0.1 as IEC 63584 and of OCPP 2.1 as IEC 63584-210.

Transmission line ratings

FERC’s Order No. 881, effective March 14, 2022, requires public utility transmission providers to implement ambient-adjusted ratings on the lines over which they provide transmission service, and requires RTOs and ISOs to set up the systems and procedures that let transmission owners update those ratings electronically. The rule defines an ambient-adjusted rating as one that applies to a period of no more than an hour and reflects an up-to-date forecast of ambient air temperature. Rating calculation, weather feeds and the exchange with the market operator are all software.

Energy management software development for buildings and plants

Energy management software development serves the buyers of energy rather than its producers: building owners, campuses, factories and data centers that need to measure use, cut it and prove it to regulators and investors.

Benchmarking and reporting

EPA’s ENERGY STAR Portfolio Manager offers RESTful web services that let software benchmark buildings, enter data on behalf of customers and pull ENERGY STAR metrics into an organization’s own tools. Custom benchmarking pipelines that read utility bills and meters, push them to Portfolio Manager and return the scores to an internal dashboard are a natural first project.

Building performance laws

In New York City, Local Law 97 requires most buildings over 25,000 square feet to meet greenhouse gas emissions limits that began in 2024, with stricter limits from 2030; the City’s goal is a 40 percent cut from its largest buildings by 2030 and net zero by 2050. Owners of many buildings need software that forecasts each building’s emissions against its limit and tracks the projects meant to close the gap.

Energy management systems

The Department of Energy’s 50001 Ready program recognizes facilities that attest to an ISO 50001-based energy management system, and is self-paced, free and does not require external audits. Software that supports such a system tracks energy performance indicators, baselines, action plans and reviews, which is mostly a data and workflow problem.

Custom energy management software development or a platform

Custom energy management software development makes sense when the portfolio mixes building types, meters and data sources that a packaged platform handles poorly, or when results must flow into finance and capital planning systems. For a handful of similar buildings, a packaged platform with an integration or two is usually cheaper. Our dashboard development page covers the reporting layer in more detail.

Energy app development: field crews, customers and traders

Energy app development splits into three audiences with very different needs: crews who work offline in difficult conditions, customers who open the app during an outage or a high bill, and traders or dispatchers who need speed and accuracy above all.

Field crew and inspection apps

Offline-first storage, large touch targets, camera and barcode capture, map views of assets and conflict-free sync are the basics. Crews judge an app by whether it saves them steps on the worst day of the year, not the best one.

Customer apps and outage communication

Outage reporting, restoration estimates, usage history, payment and program enrollment are the core features. An outage spike is a load test nobody schedules, so these apps need caching, queueing and graceful degradation designed in from the start.

Trading, scheduling and dispatch tools

Internal tools for schedulers and traders are often desktop or web applications rather than mobile apps. They need fast data, clear audit trails and careful permissions, and they are usually built around existing market and risk systems.

Mobile and web apps are built the same way across industries; what differs here is the data and the security boundary. Our app development agency page explains how apps are scoped and built, and the cross-platform app development page covers one codebase for iOS and Android.

IT and OT integration: SCADA, historians and the enterprise

Many energy software problems turn out to be integration problems. The rule of thumb is that data flows out of operational technology to the enterprise through controlled, documented paths, and commands flow back in only where the owner’s engineers have designed for it.

Where systems sit

The ISA-95 standards describe a model in which level 2 covers PLCs, distributed control systems and other control devices, level 3 covers manufacturing operations management such as manufacturing execution systems (ISA’s own description of level 3 also names SCADA), level 4 holds business systems such as ERP, and the standard deals mainly with the interface between levels 3 and 4. Energy companies use the same idea: control systems at the bottom, operations data in the middle, business systems at the top, with security boundaries between them.

Read-only by default

Analytics, reporting and customer tools rarely need to write to a control system. Building them to read replicated data in an intermediate zone, rather than to query a SCADA master or historian directly, keeps the operational network smaller and the security review shorter.

Time-series data

Historians store tag data at high frequency. Moving it to an analytics platform means mapping tag names to assets, handling gaps and timestamps, and deciding what resolution each user needs. Getting the asset mapping right is often the longest task.

When software must write back

Some projects do need to send setpoints or schedules, for example to batteries or to distributed resources under a demand response program. Those paths need engineering sign-off, protocol-level controls, logging and test plans agreed with the operations team before development starts.

Each standard has its own publisher: IEEE lists IEEE 1815, the DNP3 standard, now marked inactive-reserved; the IEC publishes the IEC 61850 series on communication networks and systems for power utility automation, and the OPC Foundation’s OPC UA overview describes OPC UA, released in 2008, as a platform-independent, service-oriented architecture. Projects that need custom connectors to other systems are covered on our API development and backend development pages.

What does NERC CIP mean for software you build or buy?

If software touches a BES Cyber System, its supporting systems or the information that describes them, it falls inside the registered entity’s CIP program. The obligations stay with the entity; the vendor’s job is to build software and processes that let the entity meet them with evidence.

NERC’s Critical Infrastructure Protection standards are listed on its CIP standards page. The ones a software project meets most often are summarized below from the standard texts; the entity’s own compliance team decides how each applies to a given system.

Impact categorization comes first

CIP-002-5.1a exists to identify and categorize BES Cyber Systems so that security requirements match the impact a compromise could have. Control centers that perform reliability coordinator functions, for example, rate high impact. A vendor should ask for the impact level of each system early; the answer changes the architecture.

Remote access

CIP-005-7 requires Interactive Remote Access to applicable high and medium impact systems to go through an Intermediate System, with encryption that terminates there and multi-factor authentication for every session, and requires methods to determine and disable active vendor remote access. CIP-003-9 brings vendor electronic remote access security controls into the plans for low impact assets. Build support and troubleshooting around the entity’s jump hosts, not around a vendor’s own remote tool.

Patching and configuration

CIP-007-6 sets a 35-calendar-day cycle for evaluating security patches and acting on them, and CIP-010-4 requires configuration baselines and, where the software source makes a method available, verification of the source’s identity and the software’s integrity before a baseline change. In practice that means signed releases, published checksums, release notes that name every changed component and a predictable release calendar.

Supply chain obligations

CIP-013-2 requires plans covering vendor notification of incidents, coordinated responses, notice when vendor access should end, disclosure of known vulnerabilities, verification of software integrity and authenticity, and coordination of vendor-initiated remote access. The standard notes that implementing the plan does not require renegotiating existing contracts, but new contracts are where these commitments belong.

People and information

CIP-004-7 covers personnel risk assessments, training and access management, including an access management program for BES Cyber System Information, and CIP-011-3 protects that information from unauthorized access. Network diagrams, firewall rules and device configurations that a vendor sees during a project may qualify as BES Cyber System Information under the NERC Glossary definition; ask the entity how it classifies them.

Network monitoring inside the perimeter

CIP-015-1 covers internal network security monitoring, with the stated purpose of improving the chance of detecting anomalous or unauthorized network activity. Software deployed inside monitored networks should behave predictably on the wire, so its normal traffic can be documented and anything unusual stands out.

Which pipeline and oil and gas rules reach software?

Two federal regimes reach pipeline software most directly: TSA’s cybersecurity directives for notified critical operators and PHMSA’s control room management rules, which reach the SCADA displays controllers use.

TSA Security Directives Pipeline-2021-01G and 02G

TSA lists its directives on its security directives page. Two pipeline cybersecurity series are current: SD Pipeline-2021-01G, Enhancing Pipeline Cybersecurity, effective January 16, 2026 through January 15, 2027, which requires a Cybersecurity Coordinator, incident reporting to CISA and a cybersecurity vulnerability assessment; and SD Pipeline-2021-02G, Pipeline Cybersecurity Mitigation Actions, Contingency Planning, and Testing, which took effect on May 3, 2026 and expires on May 2, 2027. Both apply to owners and operators of hazardous liquid and natural gas pipelines and LNG facilities that TSA has notified are critical. Under 02G they must run a TSA-approved Cybersecurity Implementation Plan, maintain network segmentation designed to keep an IT compromise from disrupting operational technology and the reverse, keep an incident response plan that includes the ability to isolate IT and OT systems, exercise it at least annually and follow a Cybersecurity Assessment Plan.

PHMSA control room management

For gas pipelines, 49 CFR 192.631 applies to operators whose controllers monitor and control a pipeline through SCADA. Among other things it requires operators to apply named sections of API RP 1165 whenever a SCADA system is added, expanded or replaced, and to run a point-to-point verification between SCADA displays and field equipment when equipment is added or moved or other safety-related changes are made. 49 CFR 195.446 sets the equivalent requirements for hazardous liquid pipelines. Custom display or alarm work has to fit the operator’s procedures for both.

What this means for a project plan

Budget time for the operator’s change management, testing in a non-production environment that mirrors the control room, and documentation the operator can add to its compliance records. A vendor that has not planned for those steps will either miss its dates or ask the operator to cut corners.

FERC orders and federal rules that create software work

Several recent federal rules were written about markets, line ratings, chargers and security rather than about software, yet each one created a new class of software project for utilities, market operators, developers and charging networks.

Why rules turn into software

Each of these rules asks for something to be measured, exchanged or proven on a schedule. Spreadsheets cope for a pilot; they do not cope with hourly line ratings, thousands of aggregated devices or a regulator’s audit. That is the point at which a custom tool, or a custom layer on a packaged one, pays for itself.

Keep rules in configuration

Rules change. Software that stores thresholds, deadlines, formulas and report formats as configuration, with a history of who changed what, survives the next order or directive. Software that hard-codes them has to be rebuilt.

Security frameworks to build against, beyond compliance

Compliance standards say what must be true; engineering frameworks say how to get there. Three public frameworks cover most of what an energy software team needs.

NIST SP 800-82 Rev. 3

NIST SP 800-82 Rev. 3, the Guide to Operational Technology (OT) Security, was published in September 2023. NIST has since released an initial public draft of Revision 4, with comments due by November 30, 2026. It is a detailed public reference for securing OT environments and a sensible baseline for any vendor working near them.

ISA/IEC 62443

The ISA/IEC 62443 series defines requirements and processes for secure industrial automation and control systems. Part 4-1 sets secure product development lifecycle requirements, Part 3-3 sets system security requirements and security levels, and Part 2-1 sets security program requirements for asset owners. Asking a vendor how its development process maps to Part 4-1 is a fair test of maturity.

DOE’s C2M2

The Department of Energy’s Cybersecurity Capability Maturity Model, now at version 2.1, evaluates cybersecurity practices across both IT and OT. DOE offers a no-cost self-evaluation for US energy sector organizations. Running it before a large software program shows where the new system will lean on weak practices.

Application security basics still apply

Our software work follows established guidance such as the OWASP Top 10 and the NIST Cybersecurity Framework, with automated tests on every change and code review before it merges. Energy projects add OT-specific controls on top of those basics; they do not replace them. The website security page covers the public-facing side, such as portals.

Cloud, on-premises or hybrid for energy software

A hybrid design fits most energy software: control and protection stay on premises, analytics, portals and collaboration move to the cloud, and a controlled zone in between handles replication. The deciding questions are data classification and latency.

What usually stays on premises

Control systems, protection, anything that issues commands to field equipment and anything the CIP program places inside an Electronic Security Perimeter. These systems change slowly and on the owner’s schedule.

What usually moves to the cloud

Customer portals, analytics on replicated data, forecasting, reporting and mobile app back ends. These gain from elastic capacity and managed databases, and they can be designed so that no command path leads back into operations.

Information that needs care either way

BES Cyber System Information, customer usage data and commercially sensitive market data each come with their own handling rules. Decide where each class may be stored, who may see it and how access is reviewed before choosing a hosting model. The trade-offs between providers are compared on our AWS vs Azure vs Google Cloud page, and moving existing systems is covered under cloud migration services.

Custom energy software development or a packaged product?

Buy the commodity and build the edge. Billing, standard outage management and core asset records are mature product categories; integrations, workflows unique to your crews and analytics that join several systems are where custom software earns its cost.

Questions that settle the decision

Is the process how you compete or comply in a way others do not? Does the packaged product’s roadmap reach your requirement within your deadline? Would licensing for the next five years cost more than building and running the software? Can the product’s APIs carry the integration, or would you be building around its limits? Our custom software vs off-the-shelf guide works through the cost side.

The usual answer is both

Where a standard tool already fits, it should be kept and integrated rather than replaced. The custom part is the layer that makes the packaged systems work together for your people and your regulators.

How an energy software project runs, from discovery to support

Every project starts with a written scope and ends with software the client owns and can operate. In between, energy work adds a security design step and testing against realistic operational data.

Discovery

Interviews with the people who do the work, a map of the systems and data involved and an early conversation with the compliance and OT security teams. The result is a written scope with priorities, acceptance tests and a price.

Design and security review

Architecture decisions are written down: where each component runs, how it is reached, how it is patched and how releases are verified. Doing this before development is cheaper than redesigning after a security review rejects the first build.

Build

Development runs in two-week sprints, each ending with working software the client can use and a short written update. Automated tests run on every change and code is reviewed before it merges.

Test and release

Tests run against replayed historian and meter data and simulated devices, not only synthetic samples. Releases come with notes, checksums and the change records the owner’s process asks for.

Support

After launch, a support plan covers monitoring, security patching, dependency updates and bug fixes with agreed response times, plus a steady flow of improvements from a shared backlog.

How long does energy software development take?

A focused integration or dashboard takes weeks; a first mobile app release or a portal takes a few months; field apps with ERP integration, platforms and modernization can take most of a year or more. The owner’s change windows, security reviews and testing access often set the pace more than coding does.

What slows energy projects down

Waiting for access to test environments, firewall changes that need a change window, security reviews that arrive late and data owners who were not in the room for discovery. Naming those people in the scope removes much of that delay.

What speeds them up

A single decision-maker, early security review, a realistic test data set and an agreement on what the first release does not include. Shipping a narrow first release and extending it is faster than waiting for a complete one.

How much does custom software development cost for an energy company?

Cost depends on the number of systems behind the software, the compliance scope, OT access and security review, and the testing the owner requires, not on the energy label. A quote follows a written scope.

What pushes the price up

The number of systems behind the software, OT access and security reviews, offline mobile sync, device protocols and certification, data migration, and the evidence and documentation a regulated owner needs. A portal that reads from one system costs a fraction of one that reconciles four.

What keeps it down

A narrow first release, reuse of the owner’s existing identity and logging tools, read-only designs where they will do and test data prepared before development starts. We price a written first-release scope, then run further work from a prioritized backlog on a monthly plan.

Should energy software be built onshore, nearshore or offshore?

Team location matters in energy work because access reviews, background checks and incident response all involve named people and time zones. Choose the model that fits the systems the team will touch.

Matching the model to the systems

A public portal or an analytics tool on replicated data can be built by almost any competent team. Work that needs access to systems in a CIP program or a pipeline’s OT network is easier with a small, named team whose access the owner can review and remove quickly. Nearshore software engineering services can suit the first kind of work; check the second kind carefully. A search for a custom software development company near me returns a map of firms, but for energy work proximity matters less than time zone, contracts and how quickly named people can be reached during an incident.

Where Progression fits

Progression Agency is headquartered in New York City with a US-based team and US contracts, and works with clients across the United States and worldwide. Our energy software development services follow the same process as our other custom software work: a written scope and estimate before development, then working software every two weeks. The trade-offs of outsourced teams generally are covered on our app development outsourcing and dedicated developers pages.

How to choose an energy software development company

When you compare energy software development services, choose on evidence of how the vendor will work inside your rules, not on a list of logos. The requirements below can each be checked in a conversation or a document request before you sign.

Questions to ask in the first meeting

What would you need from our compliance and OT security teams in week one? Which of our systems would you avoid touching, and why? How do you test against realistic operational data without exposing it? What does your hand-over package contain? What happens to our code and accounts if we part ways?

Red flags

A vendor that wants its own always-on remote access tool, proposes writing to control systems for a reporting project, cannot explain how its releases are verified, keeps code in its own repositories or treats CIP and TSA requirements as the client’s problem alone.

Energy software companies and custom developers

Energy software companies that sell products know their own platforms deeply and are the right call for the core system. A custom enterprise software development company is the right call for the layer around it. The software development company page explains how we scope and build custom software in general; this page covers what changes when the client is an energy company.

Choosing an energy management software development company

An energy management software development company should be judged on data handling more than on dashboards. Most of the value is in getting meter, bill, building automation and production data into one consistent model.

Data sources it must handle

Utility bills and interval data, Green Button downloads where available, submeters, building automation trends, production or occupancy data for normalization, and the outputs of Portfolio Manager or other benchmarking tools.

Outputs that matter to owners

Building-by-building performance against targets, emissions against local limits such as those under Local Law 97, savings verification for projects, and reports finance teams can trust. A good vendor asks who will read each report before designing it.

Measuring whether energy software worked

Measure the work the software was meant to change, in the units the operations team already uses. Adoption comes first: software nobody uses saves nothing.

Set the baseline before the build

Record the current numbers for the measures above before development starts. Without a baseline, every improvement is an opinion.

Report monthly, decide quarterly

Monthly numbers show whether adoption is on track; quarterly reviews decide what goes into the next release. Both should be written down and shared with the people who use the software.

AI in energy software: where it helps and where it stays out

AI earns its place in energy software on documents, text and forecasting, and stays out of control loops. The useful projects read, summarize and predict; they do not operate equipment.

Where it helps

Extracting fields from interconnection applications, permits and inspection reports; summarizing outage calls and crew notes; answering staff questions from internal procedures; classifying work orders; and improving load, price or output forecasts when the training data is sound. Our AI integration services page covers how these features are added to existing software.

Where it stays out

Protection, control and any command path to field equipment. AI outputs that inform operators should be labeled, logged and reviewable, and any decision with safety or reliability consequences stays with a qualified person.

Data handling

Customer data, BES Cyber System Information and market data each have rules on where they may be processed. Decide which model providers and hosting regions are acceptable for each class before any prompt touches real data.

How energy buyers use AI assistants to shortlist software vendors

Operations and IT leaders can now ask ChatGPT, Claude, Perplexity, Gemini, Copilot or Google’s AI Overviews for a first list of vendors. Treat the answer as a starting point and check every name against the requirements table above.

What buyers ask

Questions such as which firms build custom software for electric cooperatives, who has built OCPP charge management integrations, or which vendors understand NERC CIP remote access. Ask the same specific questions you would put to a vendor, then compare the answers with each vendor’s own pages.

What assistants draw on

An assistant that searches the web has to be able to reach a page to cite it. OpenAI documents OAI-SearchBot for search results, separate from its training crawler; Perplexity says PerplexityBot surfaces and links websites and is not used for foundation models; Anthropic describes Claude-SearchBot as indexing content to improve search results. Google says there are no additional requirements to appear in AI Overviews or AI Mode beyond normal search best practices. Google’s ads can show above, below or within AI Overviews.

What to verify before a call

Whether the vendor’s pages name the standards and protocols you need, whether its claims can be checked, who owns the code under its contracts and how it handles remote access. For vendors who sell to energy companies, our AEO for industrial companies page explains how to publish detail assistants can cite.

Testing energy software with realistic data

Energy software fails on edge cases that synthetic data rarely contains: meters that report backwards, tags renamed mid-year, devices that drop offline in storms. Test data should come from the real world, safely.

Replay, do not just generate

Replaying a season of historian or meter data through a test environment catches more defects than random samples. Masking customer identifiers keeps the replay safe to use outside production.

Simulate devices and failures

Device simulators for OCPP chargers, inverters or field gateways let teams test reconnection, firmware updates and partial failures without touching real equipment. Storm-day load on customer tools should be tested on purpose.

Agree acceptance tests in the scope

Acceptance tests written into the scope, with the data sets they run on, end arguments about whether a release is done.

Support, monitoring and patching after launch

Energy software is never finished, because the systems around it, the threats and the rules keep changing. Plan support as part of the budget, not as an afterthought.

What a support plan should cover

Hosting management, monitoring and alerting, security patching, dependency updates, bug fixes with agreed response times and a steady cadence of improvements. For software inside a CIP program, the patch rhythm should fit the 35-day evaluation cycle.

Keeping knowledge in the organization

Runbooks, architecture records and access lists should live in the owner’s systems. If the vendor relationship ends, another team should be able to continue from the documentation.

Related services for energy companies

Each of these pages goes deeper on one part of the work described above.

• Software development company: how custom software is scoped, built and supported.
• Web development services: portals and web applications.
• App development agency: field and customer apps.
• IoT app development: device fleets and cloud back ends.
• Embedded software development: firmware and device-side code.
• Manufacturing software development: plant-floor and production tools.
• Logistics software development: dispatch and delivery tools for fuel distribution.
• Telecom software development: network and field-operations software.
• Dashboard development: reporting on historian, meter and work data.
• API development: connectors between systems of record.
• Backend development services: data pipelines and services.
• Web portal development: customer and partner portals.
• ERP development: finance and supply chain integration.
• DevOps services: pipelines, infrastructure as code and managed operations.
• Cloud migration services: moving systems to managed infrastructure.
• Software consulting services: assessments, architecture and roadmaps.
• AI integration services: document and forecasting features.
• AI agent development: assistants grounded in internal procedures.
• Desktop application development: tools for control rooms and trading desks.
• Enterprise app development: apps for large internal teams.
• Python development: data and analytics engineering.
• .NET development services: extending Microsoft-based utility systems.
• UI and UX design services: interfaces crews and customers can use.
• Solar marketing agency: marketing for solar companies.
• Industrial SEO: search visibility for industrial suppliers.

Frequently asked questions