ERCG continues its ABC leadership interview series with John Bick, Managing Principal at Priority Power Management. We sat down with John and discussed several topics, including --
ERCG: Priority Power Management is one the largest ABCs in Texas (and the US) today. How did Priority get started and what were the early years like?
John Bick: Both myself and my partner, Pat Ennis, began our careers at TXU/Oncor and its predecessor companies back in the regulated days. We both worked in TXU’s Strategic Accounts (Key Accounts) group with responsibility for TXU’s largest commercial and industrial customers. Pat was in Midland responsible for relationships with large oil and gas customers. I was in Dallas and was a manager of the group. When SB 7 passed in 1999, we began to prepare the organization to transition from a regulated account management role to a competitive retail electricity supply sales role.
I continued with TXU during that transition, but Pat decided to leave the company and began reaching out to his oil and gas customers to help them prepare for deregulation. A group of Midland oil and gas executives (we call them the “Midland mafia” – they do deals together) saw an opportunity to create a company that would aggregate their power demands and utilize their collective large buying power to negotiate favorable competitive retail electricity supply when deregulation commenced. Together with Pat and these oil and gas executives, Priority Power Management, LLC was born and established in January 2001.
On March 1, 2001, Priority was granted and issued a registered Aggregator license by the Public Utility Commission of Texas. We were the 11th company to become a licensed Aggregator. Today, there are 326 licensed aggregators listed on the PUCT website, and only six (6) of the ten (10) that were ahead of us are still listed.
With its Aggregator license, Priority began to educate customers on deregulation and the process for buying competitive retail electricity supply. Priority assembled an initial group of customers to participate in the deregulated pilot program and negotiated its first supply deal that would begin in June 2001 for a group of customers, mostly oil and gas companies, representing about 40 MW.
When January 2002 rolled around, it was pretty crazy. Since the initial period of deregulation included a Price-to-Beat (“PTB”), the default price customers paid if they did not switch to competitive retail electricity provider (“REP”), and the competitive supply rates were significantly below (~40%) the PTB, it was a no brainer to switch to a REP to achieve significant savings.
The challenges awaited as the REPs had significant issues rendering a correct invoice, or an invoice at all. There were some REPs where the customers did not receive an invoice for many months, and even then it was not correct. So, there were a lot of growing pains in the early days and a significant amount of Priority’s time was spent working on behalf of our customers auditing and pressing REPs for correct invoices.
Meanwhile, I was still back at TXU and transitioned out of the Strategic Accounts group into TXU Solutions group, where I was responsible for developing large national energy outsourcing deals. The value proposition was based on the premise that large companies with significant energy spend did not have the internal sources or expertise to effectively manage energy supply procurement, risk management and capital programs directed an energy efficiency. Our solution was to outsource these functions where we would take on these responsibilities under a long term outsourcing agreement, with specific service levels and performance guarantees.
This was also a pretty crazy and exciting time. We were competing with the likes of Enron Energy Services, Sempra Solutions, Johnson Controls and others. The deals that were getting done were innovative and unimaginable just a few years earlier.
Then came the fall of 2001. In August 2001, questions about Enron began to surface. In September, the nation experienced the worst nightmare of the terrorist attacks in NYC. By December, Enron had declared Chapter 11 bankruptcy, the largest in U.S. history. The ripple effects continued, and by December 2002, TXU’s European business unit declared bankruptcy. In early 2003, faced with a significant decline in its stock price, TXU decided to discontinue all business units other than electric delivery and retail supply of electricity in Texas, which included the winding down of TXU Solutions – and I was without a job.
I left TXU in March 2003 and began seeking my next opportunity. I saw the value of the outsourcing model and what we were doing at TXU Solutions. The timing was just bad given everything else that was going on in the market. I pitched an energy outsourcing business plan to some large companies, but they just didn’t get it – or maybe, they just didn’t get me.
Regardless, after a couple of months on banging my head against the wall and needing to find a source of income to support my family, I had an idea. The idea was to latch on to the wave of deregulation in Texas, lead with supply management services to build a base of customers, and then expand services beyond supply management with that customer base, effectively building the outsourcing model one step at a time. All I needed was an entry point to build that base of customers.
I figured the quickest way to begin was to affiliate myself with an existing firm in Texas providing electricity supply procurement and/or aggregation services. I reached out to two (2) people that I knew well from my TXU days.
The first was the late Carlos Ruffino, the founder of POCO Energy Group, which was later acquired by Summit Energy, which was then later acquired by Schneider Electric. The second was Pat Ennis at Priority.
I discussed my ideas with both Carlos and Pat, who were both gracious and open to my ideas. I knew some of the oil and gas investors in Priority since I grew up in Midland, so I decided to fly out to Midland to meet with them and Pat. Over a lunch meeting in the Petroleum Club, we discussed expanding Priority’s reach outside of west Texas and oil and gas customers, and the opportunity to grow the business beyond aggregation and supply management services. In just a little over an hour, we stood and reached across the table, shook hands, and PPM Dallas was agreed to be formed. Now, that’s how a deal should get done, with a hand shake!
In July 2003, PPM Dallas began operations to grow and expand Priority. From there, Pat and I worked together to grow the business to what it is today. We are very fortunate and blessed to have a great family of employees and customers that value our services.
ERCG: Similar to other very large ABCs, commodity procurement is not the majority of your revenue. In Priority’s case, it’s oil & gas infrastructure – what makes your company a leader in this space?
Bick: I wish I could say that it was a conscious strategic decision to enter the energy infrastructure space, but the truth is that it began by happenstance. As a part of our normal services offering and process, we work with our clients to understand their current and future load growth requirements. This helps in our discussions with our clients in developing an appropriate supply procurement strategy that will meet their operational and financial goals.
In parallel, we are managing the process of completing new load forms and requesting new electric service with the Transmission and Distribution Service Providers (“TDSPs”) on behalf of our clients, and working with the TDSPs to provision electricity service to new meters.
Following the nation’s financial collapse in 2009, we began to see an uptick in the amount of new exploration and development by our oil and gas clients in west Texas. By late 2010 and through 2013, there was a full boom occurring. Our oil and gas clients could not get power fast enough. The utilities were overwhelmed with requests, and often times, were out of capacity requiring significant upgrades to their system to provide the service requested, and at significant expense.
Our clients turned to Priority to help them evaluate their options. It was a natural fit. After all, most of our staff (70%) had begun and spent long careers at the utility, responsible for working with customers to build infrastructure to provide electric service. We understood the rates, regulatory, electric service guidelines, transmission and distribution engineering, construction and all other aspects required to provide this service. Thus, we are uniquely positioned to provide expertise in this area such that we can seamlessly integrate it with supply management and demand response services.
We decided to begin offering infrastructure services modeled after our supply management services. That is to say, we remain completely independent and unbiased in terms of which equipment vendors and contractors that we use to develop and complete the projects. Our job is to act as an extension of our client’s staff, evaluating the best approach from a cost, timing and reliability perspective, then to implement the solution to meet our client’s goals.
We completed our first project in 2013 and it’s been gangbusters ever since. In 2018 alone, we will develop and deliver twenty (20) high voltage substations, and associated transmission and distribution networks, as well as many other infrastructure projects across Texas, New Mexico, Oklahoma and Colorado.
Today, we are a leader in developing and implementing private electric energy infrastructure solutions. Whether it’s connecting the customer to the grid, developing a standalone microgrid with generation operating in island mode, or a hybrid model.
ERCG: Please explain the connection to infrastructure projects and retail energy procurement. Also, can you describe an example of a recent project where Priority added a lot of value to one of your clients?
Bick: The connection to infrastructure projects and retail energy procurement is rather simple. If a customer looks at their electricity bill, there is a section on retail supply charges and a section on regulated delivery charges from the TDSP. A customer is concerned about what their total delivered electricity cost are, not just about cost of the competitive retail electricity supply component. Thus, it requires that Priority, as the customer’s advisor, has a full understanding of the regulated TDSP charges as well, and if there are options to reduce these costs.
Each TDSP’s rate structures are different, but generally speaking, if a customer makes an investment in electric energy infrastructure to receive a higher voltage level of service, then the delivery charges are lower. As a result, it becomes an economic evaluation to determine the amount of savings that a customer may realize for an investment in electric energy infrastructure, and the ROI that the project may yield.
This two-pronged approach of evaluating both electric energy infrastructure options, as well as competitive retail supply options, provides the customer with a holistic approach to their entire electric energy spend from a supply and delivery perspective.
One example was a company that was planning to build a new large natural gas cryogenic processing plant in west Texas. Like most customers, they were focused on what they knew best, which in this case was identifying a site to construct the new plant that would optimize their operations of collecting gas from their oil and gas producers through a gathering system and transporting it through a pipeline to the new plant. Electricity service was not at the top of the list for items of concern.
However, when they went to contact the local utility – a rural electric cooperative – to get electric service, they found out that the cooperative could not provide the 20 MW of electric service the plant was requesting without significant upgrades and cost to the customer, and it would take several years to complete the upgrades.
At this point, rates were not even the issue. The issue was getting adequate and reliable electric service when they needed it and with least upfront cost as possible.
A Priority representative had reached out to the company to inquire about the new plant and to engage in discussions about our services. Once we were engaged, it was determined that the new plant site was located in single-certificated service area of the cooperative and options were limited at that site.
Priority investigated alternative sites that would provide the capacity required and give the customer access to the competitive retail marketplace. We identified a site that would place the new plant about 3-miles from its initial location, in an area certified to an investor owned utility, giving the company access to the competitive retail marketplace, and was about 1.5-miles from a 138kV transmission line with available capacity.
We quickly developed a financial model to evaluate all of the options, considering both upfront and ongoing expense, including the expense to extend the company’s pipeline an additional 3-miles to the new proposed plant site location, and showed the customer the benefits of moving their plant.
Ultimately, the customer did decide to move the plant. Priority provided a turnkey solution to develop the private electric infrastructure (a 1.5-mile 138kV transmission line, a high voltage substation, and 25kV primary distribution) to connect the plant to the utility’s transmission line. We also negotiated and procured the competitive retail electricity supply for the customer. The customer benefited from being able to meet their desired startup date for their plant, and still saved over 30% on their electric energy costs.
ERCG: Priority is no stranger to M&A activity. What is the story behind the AMEN Properties’ brief ownership of Priority? On the other side, how have you handled the acquisition of other firms and people into the Priority family?
Bick: The AMEN story is a little long, but here goes.
In the early days, some of Priority’s limited partners were also executives at AMEN Properties. AMEN was a publicly traded company on NASDAQ and was formed to hold a significant Net Operating Loss (NOL) that they had gained from some other investments in dot com companies that went by the wayside when the dot bomb hit. AMEN was purchasing cash generating companies and assets, like office buildings and oil and gas royalties and working interest, in order to utilize the NOL.
The guys at AMEN that were also LPs in Priority, came to us in 2004 and had interest in starting a REP. We introduced them to Kevin Yung, a longtime friend and colleague that we knew from TXU, which had been a part of starting another REP in the Dallas area. In July 2004, AMEN created W Power and Light, a REP based in Midland. At that time Priority was still a private company with no affiliation to AMEN or W Power and Light – we remained at arm’s length to avoid any perceived appearance of conflict.
Through 2004 – 2005 timeframe, both Priority and W Power and Light were doing well, albeit as completely separate businesses. We observed how the market was evolving, with large energy companies forming vertically integrated organizations that had generation, wholesale trading, and retail operations to be able to serve customers more effectively and participate in the entire energy value chain – companies like Constellation as an example.
Then we thought to ourselves, what if AMEN could create a mini-version of these larger companies? We could use AMEN’s stock as currency to acquire other firms and fill in the pieces of the value chain. That idea was the precursor to Priority being acquired by AMEN in May 2006.
After the Priority acquisition, AMEN then held ownership in Priority – the customer end of the value chain, W Power and Light – the retail electricity supplier that also engaged in wholesale trading and risk management, and it had optionality in natural gas supply through its oil and gas properties. We sought out to develop a large natural gas combined cycle generating plant south of Dallas, which did not materialize – thank the Lord given today’s generation market.
Then the summer of 2008 hit. Crude Oil went to $140/bbl, natural gas went to $14/Mcf, and ERCOT real-time prices spiked to monthly averages of near $100/MWh. AMEN was posting large amounts of cash at ERCOT for credit for W Power and Light, and viewed this as lost opportunity working capital that could be used for more oil and gas investments. Consequently, AMEN decided to wind down W Power and Light and discontinued its operations in October 2008.
This left Priority still within AMEN, but the strategy of developing a vertically integrated energy company went by the wayside. That’s when Pat and I approach AMEN about a management buyout to acquire Priority back from AMEN. AMEN was agreeable. They issued us some warrants and options to purchase Priority that were exercisable upon achieving certain financial milestones. We thought it would take us a couple of years to achieve the milestones, but we did it in 9 months. On October 1, 2010, Pat and I acquired Priority from AMEN and are now the sole owners.
As for how we have handled the acquisition of other firms and people into the PPM family, we have done it successfully multiple times. The acquisitions included EnergyTX, PARenergy, Cogdill Enterprises, and THG’s supply business. Each acquisition did present some challenges, but we were able to work through those because we did our homework upfront and knew what we were getting into.
ERCG: Is Priority exploring other M&A opportunities now? If so, why now?
Bick: We are always looking for ways to grow our business that will also benefit our current and future customer base. Our business has grown significantly since Pat and I acquired it from AMEN, nearly seven-fold in the last 7-years. This year will be a record year for us, again. We are reaching a point where we need to think even broader to sustain our growth. So, we are looking at various strategic opportunities that will take us to the next level.
ERCG: Switching gears to commodity procurement – what is your philosophy on ABC fees? Do you feel it is important for your clients to know what they are paying and why?
Bick: Priority has always taken the position that our clients should know what they are paying for, and how much they are paying. We have a written agreement with our clients that spells out our scope of services and our compensation. That compensation can come in various forms, from volumetric fees (mils) embedded into a supply contract, fixed monthly consulting fees paid directly by our client, development fees for infrastructure projects, certain costs per bill processed and audited for our data management services, etc.
I am not personally a proponent for trying to regulate or cap how much an ABC can charge for their services. I still run across instances where a prospective customer asks me to review their deal, and I am able to peel back the onion and see that an ABC did their deal and the fee was very high – at least in my estimation. But, that just gives us an opportunity to differentiate Priority, and gain a new customer.
Our approach of charging a fair fee that is commensurate with the services we are providing and the value we deliver has worked well for us over the years. Some of our largest customers are still with us since the very beginnings of the company, some 17 years later. Pat likes to remind some of our younger sales consultants – and even me at times – “Pigs get fat, and hogs get slaughtered”. Truth.
ERCG: What qualities do you look for in an ideal supplier partner?
Bick: Priority values suppliers that share the same enthusiasm as we do for outstanding customer service to our clients. That is probably number one. That includes having an assigned Account Manager that we can go to with any issues, being proactive and following up on open items, and being timely with responses and pricing requests.
Certainly the ability for suppliers to offer products and services that meet our clients’ needs is also very important. The suppliers that get creative, and are flexible in contract terms and product offerings, get a lot of points with me.
Having said all of that, price competitiveness is paramount.
ERCG: You’ve seen Texas electricity price volatility before. Do you have a perspective on the current price environment – how it will impact your clients and the types of solutions ABCs can provide?
Bick: Given that we have been in the market since the pilot in June 2001, we have in fact seen the full cycle of low and high – very high – prices. It’s been very interesting as each cycle has had its own set of dynamics with all combinations of low/high heat rates x low/high gas prices, ancillary services and congestion blowouts, and retail margin adjustments along the way.
I think back to 2005 when hurricanes Katrina and Rita hit the gulf coast and gas prices skyrocketed to $12+/Mcf causing spot and forward power prices to be at all-time highs. Customers on heat rates that had not locked gas were scrambling to decide if and when to lock gas. Customers that were coming off of fixed priced contracts were facing significant price increases for forward deals and trying to decide whether to lock in a price, or float the market with the hope that it would come off.
Those events kicked off the wave of focus on hurricane forecasts and whether or not natural gas supply from the gulf would be interrupted, causing gas prices to spike. This was of course before the shale revolution of onshore natural gas supply, which really showed up in the market in 2008 sending gas prices to near $2/Mcf.
About that same time, wind power generation was growing in ERCOT, specifically in west zone. Wind generation capacity nearly doubled from 4785 MW in 2007 to over 8000 MW in 2008. CREZ had not yet been built, and the wind power generation flooded west zone, trapped by transmission constraints limiting west to north flow to ~4500 MW. This caused west zone heat rates to drop to record lows in the 5.0 – 6.0 range. We saw this as a unique, and short-window opportunity, to lock in historical low heat rates before CREZ was completed, which would unlock west-to-north flow. We had serval of our clients enter into 10-12 year supply contracts locking in these heat rates that were in the 5.0’s. It was pretty incredible, particularly as we began to experience lower monthly gas settlement prices going forward, resulting in very low power prices for these clients.
Last year in Q3 of 2017, we identified another long term buying opportunity as the forward curve for heat rates and gas prices consolidated at what we believed to be a technical floor. As a result, we had many clients lock in fixed price power contracts extending out to as far as 2031 at unbelievably low prices. Sure, there is always a possibility that prices could go lower, but statistically the upside risk far outweighs the downside opportunity. Moreover, there is certainly something to be said about taking price risk off the table for an extended period of time.
But, no time to rest, as Vistra announced the closure of some of its coal plants in October 2017, and we saw the market react as near-term curves began to rise. Continued reinforcement from Vistra and NRG’s CEOs about the challenges of out-of-the-money generation and predictions for more retirements. The market dynamics were changing yet again. And, let’s not forget the science of predicting weather and its effect on power prices. Forecasters began predicting a hotter than normal summer for 2018, ERCOT revises its forecast and announces tight reserve margins for summer 2018. Here we go again, prices for balance of 2018 and near-term tranches spike. Now, when I say spike, we are talking about power prices going from the mid $30s to the mid $40s. Nothing like we saw back in 2008. So, we have to keep things in perspective.
The biggest challenge we are currently facing is the blow out of congestion costs in west zone, again.
In 2012 we saw west zone congestion rise from an average of ~$3.27/MWh in 2011 to ~$11.65/MWh in 2012. The issue was largely driven by significant load growth by oil and gas customers combined with aging transmission infrastructure that needed significant upgrades. Priority took a leadership role in advocating for more transmission infrastructure investments in west zone to provide reliable service and an efficient network to flow power from the most economical generation. It took a couple of years, and some ~$600 million, but upgrades were constructed and congestion costs dropped to ~$0.50/MWh by 2016.
Today, we are in another oil and gas boom and oil and gas related load growth in west zone is unprecedented. The TDSPs are better prepared this time around than they were back in 2012, but still lag behind load given the length of time it takes to go through the ERCOT stakeholder process in order to get approval to build more transmission. As a result, we have seen west zone congestion rise from a monthly average of $0.83/MWh in January 2018 to ~$31.40/MWh last month, and ~$32/MWh this month to date. We applaud ERCOT’s Board of Directors recent approval of the Far West Texas Regional Planning Group projects to spend ~$327 million to upgrade transmission in west zone. This will certainly help, but it will take time to get done and in the meantime, customers will face significant congestion costs if they have not hedged congestion.
We believe that transmission upgrades are critical, but we also see opportunities for distributed generation to be an important part of the solution. We are actively exploring DG opportunities to provide reliable power supply and economic market participation either behind the meter, or grid connected.
As advances in technology continue to drive down costs for solar, battery storage, distributed generation, and learnings from early adopters in intelligent microgrids reform the way we think about traditional energy markets, the opportunities for creating significant value for end use customers are boundless.
For more information, contact Young Kim, Principal at ERCG
Phone: (617) 903-0877