NorthWestern Energy Group Inc (NWE) 2013 Q2 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the NorthWestern Energy Corporation's second quarter 2013 financial results conference call. Today's call is being recorded. At this time I would like to turn the conference over to Mr. Travis Meyer. Please go ahead, sir.

Thank you, Catherine. Good afternoon and welcome to NorthWestern Corporation financial results conference call and webcast for the quarter ended June 30, 2013. NorthWestern's results have been released, and a release is available on our website at www.northwesternenergy.com. We also filed our 10-Q after the market closed yesterday. Joining us on the call today are Bob Rowe, President and CEO; Brian Bird, Vice President and Chief Financial Officer; Kendall Cleaver, Vice President and Controller; John Hines, Vice President of Energy Supply; and Mike Cashell, Vice President of Transmission.

This presentation contains forward-looking statements within the meaning of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements are based upon our current expectations and speak only as of this date. Our actual results may differ materially and adversely from those expressed in our forward looking statements as a result of various factors and uncertainties, including those listed in our annual report on form 10-K, recent and forthcoming 10-Qs, recent form 8-Ks and other filings with the SEC. We undertake no obligation to revise or publicly update our forward looking statements for any reason.

Following our presentation, those who are joining us by teleconference will be able to ask questions. A replay of those -- excuse me, a replay of today's call will be available beginning at 6.30 Eastern time through August 25, 2013. To access the replay dial (888)203-1112 then access code 185-6638. Again, that is (888)203-1112 access code 185-6638. A replay of today's webcast will also be available on our website.

I will now turn it over to our President and CEO, Bob Rowe.

Thank you, Travis. As many of you know, we've moved most of our board meetings around our service territory, so today we are at our Brookings, South Dakota office. Yesterday we had our board meeting on the campus of South Dakota State University. Last night we had a great community event and then this morning a meeting with our employees here in Brookings. On Tuesday we were about 150 miles northwest from here in Aberdeen, South Dakota, where we held a dedication and ribbon-cutting for our new Aberdeen Generating Station. That's our most recent energy supply addition in South Dakota, and I'd recognize the successful completion and effort put forth by many people both inside and outside the Company. This is a 60-megawatt gas peaker came into service on April 30, and has already been called upon several times to help meet heavy loads the from summer temperatures that we've been experiencing here, and of course, other parts of the country as well.

Similarly, just a few weeks earlier, we held a dedication for our 40-megawatt wind facility in Judith Basin County in Montana. So we have a lot of experience cutting ribbons over the last few weeks. And that facility, Spion Kop, was completed and placed into commercial operation in December. On our last call in April we mentioned the capacity factor at Spion Kop was far exceeding our expectations, but we also cautioned that winds typically do slow in the spring and summer months. However, with spring behind us and already in the middle of the summer, we are still blown away, pardon the really terrible pun, with a capacity factor of around 46%. We're confident that these two new assets, along with our pending natural gas acquisition that we'll discuss a bit more, are going to be great addition to our gas and electric energy supply portfolios that are going to help us provide our customers clean, cost-effective and reliable energy for decades to come. I'll provide an update on the pending natural gas transaction a little bit later.

I know most of you have already read our Q and our release, and as you saw, we've experienced improvement in gross margin, operating income, net income as compared to the second quarter of last year. I'll come back and cover off in more detail on some of the operational details, but first I'm going to turn things over to Brian to report on the similar progress on the earnings side. Before I do that, again, I do want to announce that our Board of Directors did declare a common stock dividend of $0.38 per share payable on September 30 to shareholders of record as of September 13. Brian?

Thanks, Bob. As Bob mentioned, we again are pleased with our financial results this quarter. It's not always fun to be the CFO, but a nice, solid quarter like this certainly makes it more enjoyable. We reported consolidated net income of $14.3 million or $0.37 per diluted share for the quarter ended June 30, 2013, as compared with net income of $11.4 million or $0.31 per diluted share for the same quarter in 2012. The story this quarter is fairly simple. Improvements in weather on a year-over-year basis and the addition of our growth projects in electric generation and gas production are the primary drivers for improved results.

To provide a little more detail, gross margin was $153.3 million or $5.1 million better than last year, primarily due to the following -- An increase in natural gas and electric retail volumes, due primarily to colder and more typical spring weather; an increase in natural gas production margin, primarily from the acquisition of the Bear Paw assets in the third quarter of 2012; an increase in electric transmission capacity revenues, due largely to wholesale energy market pricing; margin contribution from Spion Kop placed into service late in the fourth quarter of last year; lower QF-related energy supply costs; and, although a relative low volume quarter for gas, we did also start to recognize the benefit of the natural gas rate increase we were authorized to start collecting on April 1. These improvements were partly offset by decrease in our demand-side management, or DSM, lost revenues recovered through our supply trackers; lower DGGS revenue, primarily due to an increase in our FERC related deferral after last September's initial decision from the FERC ALJ; and lower revenues from operating expenses recovered in trackers, primarily related to customer efficiency programs.

On the expense side, operating general administrative expense was $67.4 million or only $300,000 higher than the same quarter last year, primarily due to incremental operating and maintenance costs related to full production of our DSIP, or Distribution System Infrastructure Project this year, as compared to the phase-in activities in 2011 and 2012, when we deferred those expenses; also, increased labor costs, due primarily to compensation increases and some additional employees; higher plant operator costs, due to the Spion Kop acquisition and planned maintenance at Colstrip Unit 4; and also, higher natural gas production costs due to the Bear Paw acquisition. These increases were partly offset by decreased pension expense and lower operating expenses recovered in trackers, again, primarily related to customer efficiency programs.

Depreciation expense was $27.4 million, or $1 million higher than the same quarter last year. $1 million variance deserves a little more explanation, however. Depreciation expense actually increased by $2.5 million due to plant additions but was offset in part by a reduction in depreciation rates of approximately $1.5 million for the quarter, as a result of our recent third-party depreciation studies. These studies indicated on average we should assign longer asset lives to our electric and natural gas assets in Montana and electric assets in South Dakota. In addition to the $1.5 million benefit we experienced this quarter, we expect an ongoing benefit depreciation expense due to the change in rates of approximately $3 million for the last half of 2013 that will help partially offset the increases we otherwise experience due to continued investment. With gross margin up $5.1 million and operating expenses in total up $1.2 million, operating income improved by $3.9 million over the same quarter last year.

Interest expense is $1.2 million higher than last year, primarily due to increased debt outstanding, as can be expected for a growing utility. Income tax expense was $2.1 million, or $0.5 million less than last year, due in part to production tax credits coming from Spion Kop and a few other minor differences in state and other taxes. Finally, when we get down to net income for the quarter, we saw a $2.9 million improvement, moving us to $14.3 million this year from $11.4 million during Q2 last year. Our diluted share count was about 1.4 million higher this quarter than Q2 last year, due to share issuances under an equity shall program, but the $2.9 million increase in net income more than offset the dilution, resulting in a $0.06 per share improvement in EPS I mentioned earlier.

You might recall during the second quarter last year, we had two non-GAAP adjustments to reconcile to our guidance. We added $0.05 per share back from mild weather, and we subtracted $0.05 per share for an out of period release of previously deferred DSM lost revenue. Those two adjustments offset each other, so GAAP and adjusted EPS were both $0.31 per share last year. The only adjustment we would make this quarter is we estimate weather to have contributed approximately $0.02 per share benefit as compared to normal weather, so our adjusted EPS is actually $0.35 per share as compared to GAAP EPS of $0.37 a share. This reflects then a $0.04 per share improvement over the adjusted $0.31 per share earnings last year. Again, that $0.04 per share improvement was largely driven by the increase in gross margin mentioned previously. Our Press Release includes a table that shows these quarterly non-GAAP adjustments for 2012 and the first half of 2013.

And as for a reminder of the year and full year guidance, I'm certain most of you noted from our Press Release this morning we moved up both the bottom and top end of our guidance range of $0.05 per share, from $2.40 to $2.55 up to $2.45 to $2.60 per diluted share. With a solid first half of the year behind us, we feel comfortable increasing our guidance for the full year. Primary drivers for the increase are as follows -- the ongoing benefit related to the depreciation studies and our effective tax rate of 12%, which is at the low end of our initial 12% to 16% range. And these benefits are partially offset by expense timing that will push some costs anticipated in the first half of the year into the second half, and the potential impact of reduced transmission revenue as a result of the outage at Colstrip Unit 4.

As a reminder, our primary assumptions for the guidance range include consolidated income tax rate of approximately 12% of pre-tax income and normal weather in our electric and natural gas service territories for the remainder of 2013. Guidance excludes any potential additional impact as a result of the FERC decision regarding revenue collection at our Dave Gates Generating Station and any unanticipated costs due to the Colstrip Unit 4 outage. $2.45 to $2.60 still assumes approximately 38.1 million diluted average shares outstanding for the year.

Now, moving on to the balance sheet as of June 30, 2013, cash and equivalents were $7.8 million compared to $8.1 million at the same time last year. We had $232.5 million available from our revolving credit facility at June 30 this year as compared with $162 million at June 30 last year. Total debt at the end of the quarter was just over $1.1 billion. Our total debt to cap ratio was 52.8% at June 30 and is in the middle of our 50% to 55% range we continue to target. We continue to execute on our equity distribution program. During the second quarter we issued $26.1 million of equity, and in total we've issued $72.3 million since we initiated the program last year. Our equity distribution plan extends to the end of 2014 and authorizes up to $100 million of total issuances.

I look forward to your questions. So with that I'll turn it back over to Bob.

Thank you, Brian. As you heard from the earnings drivers, much of the benefit we're seeing year over year is a result of our energy supply additions. These projects provide great investment opportunities for our shareholders while guaranteeing or while providing our customers long-term certainty and price stability. At the start of the call I mentioned I'd come back and provide some more detail around our supply investments. On the gas side we were referring to our most recent acquisition as Bear Paw South. And as a reminder, this is the transaction that we announced on May 28 to purchase 64.6 Bcf of proven and producing gas production interest in the southern Bear Paw basin of north-central Montana. The $70 million purchase price also included an 82% interest in the Havre Pipeline Company.

Havre pipeline is a small regulated utility providing farm cap gas services but is primarily a gas gathering and transmission company for the Bear Paw basin. Although it is a much smaller part of the overall transaction, this piece of the transaction does require a limited waiver from the Montana Public Service Commission to allow NorthWestern to own and operate this regulated public utility as a subsidiary. The request for a waiver was filed on June 21; the deadline to intervene was July 19; and the only party to do so was the Montana Consumer Council, which, of course, would normally intervene in matters of this type. We hope to have the waiver approved during the third quarter and are targeting to close on the transaction early in the fourth quarter.

Similar to the first two gas acquisitions that we made, we are not seeking pre-approval as a condition of closing. Instead, upon closing we anticipate using the same bridging practice of using our natural gas tracker to recover expenses, depreciation, depletion and return on investment until the reserves are placed in the rate base through the standard approval process. This is a reasonably priced acquisition that we estimate to provide customers with a 20 year levelized price of $4.10 per dekatherm. On a less momentous note, unfortunately, there are no new updates on our FERC revenue allocation issue concerning the Dave Gates Generating Station since our last call. In case any of you may be less familiar with this matter, I'm going to spend just a few minutes to bring you up to speed. And those of you who know this story by heart can refill your coffee cup right now for a moment.

FERC ALJ issued an initial non-binding decision in September of '12 regarding the allocation of costs on what was then a new gas plant that we put into service in January of '11 intended to provide regulating reserves to both retail and FERC jurisdictional customers. The initial decision from the FERC ALJ resulted in an allocation that was only a fraction of the amount that we believed should be allocated to the FERC jurisdictional customers based on past practices. As a result of the initial decision we continue to defer revenue of approximately $700,000 per month and now have a cumulative deferral -- $20.7 million as of the end of June. Our briefs, as well as others from the Montana PSC, Montana Consumer Council, Bonneville Power Administration and the Edison Electric Institute, all in opposition to the ALJ's decision, are now pending before the FERC.

We have, as we have discussed before, have no assurance of timing, but we do hope the FERC will consider the matter and issue a binding decision sometime before the end of the year. The FERC is not obligated to follow any of the findings from the ALJ's initial decision and can accept or reject the initial decision either in whole or in part. If the FERC upholds the ALJ's decision and a portion of the costs are effectively disallowed, we would be required to assess DGGS for potential impairment. If we disagree with the decision, we may of course pursue full appellate rights through rehearing and until to the United States Circuit Court of Appeals, and that could realistically extend the matter into 2015.

Turning from FERC to provide a brief update on several state regulatory matters, as we mentioned in April, we continue to anticipate that our next general rate case filings could be made in 2014 based on a 2013 test year. As we have discussed before, and as we do every year, we'll run through the numbers to determine which jurisdictions are or would most likely be operating with revenue deficiencies. If a Montana electric filing is made, it would be due to significant investments that have been made to improve system reliability and capacity through our DSIP. For those -- any of you who have not heard of DSIP, that's our Distribution System Infrastructure Plan, and our other activities in Montana, including our transmission build outs to improve reliability and capacity. On the South Dakota side, a South Dakota electric filing would be driven by our environmental estimates and environmental control installations at our jointly owned facilities as well as by the construction of the new Aberdeen peaker, which, as I've mentioned, we had needed to comply with capacity reserve requirements as well as our ongoing investment in the system.

One of the regular filings that we make each year in Montana is our electric and natural gas tracker. Each year we submit electric and natural gas tracker filings for the true up of supply costs for the preceding 12 month period and recovery of projected supply costs for the upcoming 12 months. The Montana Commission reviews such filings and makes its cost recovery determination based on whether or not our supply procurement activities were deemed to be prudent. One item of note here -- our tracker filings include a request for demand-side management or DSM lost revenues. As Brian mentioned, one of our significant negative earnings drivers quarter-over-quarter relates to lower DSM lost revenues recovered through the tracker this year.

In the second quarter last year, we had received the final order on our tracker and were able to recognize previously deferred lost revenues in that case of $6.6 million. With the final order last year, the Commission also granted us the ability to include forecasted lost revenues instead of historic lost revenues. However, along with this change the Commission requested a detailed, independent study supporting the lost revenues we had requested, and that study has since been provided. So we collected the DSM lost revenues based upon the approved energy supply tracker interim rates, but we defer a portion of these revenues pending a final order. As of June 30, we have deferred revenues of approximately $2.5 million related to DSM lost revenue collected into 2013 and also $4.9 million collected during 2012, so $7.4 million in total. A hearing was held in June, and we look forward to a final order sometime during the last half of 2013.

To continue with our practice of updating on our entire pipeline of projects investing and service to our customers, with Spion Kop and the Aberdeen peaker, both online and producing energy for our customers, the next likely large addition to our electric supply portfolio would be a natural gas generating asset in Montana to help replace the power we are currently procuring from third parties. As we continue to evolve more toward a vertically integrated utility in Montana, a natural gas combined cycle combustion turbine or CCCT has been identified as a type of generation asset that can provide the flexibility to best serve our customers into the future. The benefits of this kind of an asset would include dispatchability, provision of ancillary services, baseload power and peaking power. We do, of course, continue to evaluate what we think of as opportunistic acquisitions, but we are moving forward on the development of the CCCT.

To that end we have had several meetings with a potential engineering, procurement, and construction contractor and are in the process of conducting a siting study for a nominal 250 to 300 megawatt combined cycle plant in Montana. The siting study includes a review of the availability of electric and gas transmission infrastructure; land; water; ease of permitting; necessary infrastructure, such as roads, railroads, and of course a skilled workforce. We're currently conducting specific on-site investigation concerning these subjects. We expect to complete the siting study by the end of the year, to be followed up quickly with the identification of specific technology. Consistent with the timing set forth in our 2011 Montana biennial integrated resource plan, we anticipate a 2018 commercial operation date for this new build option. We'll continue to update you on progress as appropriate, but you can also expect our 2013 Montana electric resource plan to set forth further details regarding the project. We plan to file this resource plan with the Montana Commission in about December of this year.

As a result of the RFP we issued in May, we've also signed several contracts with multiple counterparties at favorable prices for our customers, and these new contracts will help offset the rolloff of the current contracts we have with BPL Montana. And we also plan to layer in additional short-term energy contracts through future competitive solicitations, and this process will help maintain maximum portfolio flexibility until we are able to bring a more permanent generating solution online for our customers. On the electric generation front, we continue to move ahead on our environmental projects, on our jointly owned baseload plants that serve our South Dakota customers. We are in the final year of construction on the emission reduction project at the Neal 4 plant in Iowa. There, our 8.4% share of the total project is estimated to come in between $25 million and $30 million and is expected to be completed early next year. We are also the joint owners of the Big Stone plant in South Dakota, and, under the State implementation plan approved by the EPA in May of last year, the Big Stone plant is required to install and operate a new BART, or Best Available Retrofit Technology, a compliant air quality control system to reduce emissions.

Current estimated project costs for our 23.4% share is between $95 million and $110 million, and this is expected to be operational by 2016. And we did also kick off the actual dirt work on that project just a few months ago. We do have one other, much smaller environmental project in the works; this is at our jointly owned Coyote plant in North Dakota. And the North Dakota state implementation plan requires the facility to reduce its emissions. Current estimate for our 10% share of the project is about $1 million, and the equipment should be in operation by 2018.

While neither an investment growth nor an environmental project, I do want to take a minute to discuss the outage at another jointly owned generation plant in Montana. I don't have much to offer in terms of updates since our Press Release on the 15th, but as most of you know, Colstrip 4 tripped off-line on July 1, and upon initial inspection, damage to the stator/rotor assembly was evident. PPL Montana is the operator of the entire Colstrip complex, and they are developing a repair schedule and estimating the unit will remain out of service for at least six months. The estimate for total repair cost for the unit is about $30 million, and it is expected a majority of these cost will be capital costs. And it's important to keep in mind that NorthWestern participates in a reciprocal sharing agreement with PPL between units 3 and 4. And as such, NorthWestern's 30% share of both costs and output is effectively limited to 15% of each unit, making our share of the repairs about $4.5 million. We will continue to receive 15% of output from Unit 3, and that's 111 megawatts at full capacity.

Our supply group did a really nice job of immediately procuring replacement power for the term of the outage. And the costs related to the power purchase will be included in the monthly electric tracker for proposed recovery, subject to a prudence review by the Montana Commission, likely in mid-2014.

Turning back to the natural gas side of our supply portfolio in Montana, with the first two gas acquisitions we were able to serve about 9% of our 20 Bcf annual retail natural gas needs in Montana. The pending Bear Paw South acquisition will increase our owned reserves to approximately 37% of our current annual gas needs -- retail gas needs in Montana. As we have said before, we believe that by owning 50% or so of our retail gas needs, we can provide customers long-term price stability and an excellent hedge against potentially volatile gas markets. So as such we continue to seek opportunities to acquire another 13% of so to reach our 50% target, and potentially also incremental reserves as fuel for electric generation, including at Dave Gates.

Also, as with any gas producing assets, these wells have declining annual production of about 8% or so, and therefore the need exists to continue to find new producing reserves to offset declining production. Based on comments we have heard, I know a few of you listened to the Commission's work session way back on May 22, and that provided the commissioners the opportunity to comment on our 2012 gas procurement plan. In that plan we laid out our targeted ownership parameters, and on a five to zero vote the Commission issued what we thought was a very thoughtful comment letter that was generally positive and supported owned reserves, and we look to that letter as guidance.

Turning now to our distribution operations, as part of our commitment to maintain a safe and reliable electric and natural gas system, we continue to evaluate the condition of our distribution assets to address aging infrastructure and other issues through our Distribution System Infrastructure Project and related activities. The primary goals of DSIP are -- include to reverse the trend in aging infrastructure, to maintain reliability, to proactively manage for safety, to build capacity into the system, and to prepare our network for the adoption of new technologies as those make sense. We're working on a variety of solutions and evaluating the addition -- the implementation of additional technologies to prepare the overall system for the next generation of technology.

As many of you know, over the past two years we've been in the ramp-up stage of DSIP. We've been very, very pleased with how those two years progressed. We are happy we made that decision. And the first quarter of '13 marked what we would call the hard start for the remaining five years of the project. We're now in the second quarter full production. We continue to be very, very pleased with the project and excited to see the results already appearing in the field.

During '11 and '12 we utilized an accounting order from the Montana Commission to defer approximately $16 million of expense during the phase in. The amortization of these expenses will be approximately $3.1 million annually over five years, beginning of '13. This amortization is in addition to the approximately $11 million of expense we plan to incur this year for DSIP specifically. In terms of DSIP capital spending, we spent about $34 million in the ramp-up phase and plan to invest another $253 million of CapEx through 2017. Based on our current plans along with the Commission's approval of the accounting order, we believe DSIP related expenses and capital expenditures will be covered in our base rates through our general rate cases.

You might be interested in, I'd say, the degree of engagement the Commission in Montana has with this project. In the last several months we've held two daylong field briefings for members of the Commission, their staff, and for the Montana Consumer Council really covering all things DSIP. So that included an overview of all the elements of the project, a project report, a great presentation on aspects of project management, and then site visits to both electric and natural gas applications. And we sincerely appreciate the Commission and staff and the Consumer Council's interest in the operational level details of this project.

Finally, a brief update on the electric transmission side. Bonneville Power Administration, BPA, recently announced its plans to move forward with the environmental impact study on the Montana to Washington project. And this is incrementally positive news for the Colstrip 500 kV transmission line upgrade project. The EIS, the BPA EIS, is likely take two to three years. As a result of this long lead time and transmission market uncertainties that we've discussed before, we don't plan to continue quarterly updates on this project, at least until the EIS results are known and the market need is reassessed. In the meantime, we do continue to focus on both gas and electric transition needs within our service territory. In fact, we do have several upgrade and expansion projects in process that will serve to improve reliability and respond to customer growth.

Two significant projects are indicative of these activities, and these are the Jackrabbit to Big Sky transmission 161 kV line, and this is an upgrade through very rugged territory along the Gallatin River; and the new Columbus to Chrome 100 kV transmission line to respond to customer need and load growth in southwestern Montana. And we expect to spend approximately $80 million on these two projects between 2012 and 2017. We're also in the third year of a project to replace conductors on our 151 kV line in South Dakota. So, these projects are included in our maintenance CapEx as disclosed in our 2012 10-K, but they have been growing in significance over the past several years. And I do think they're worth highlighting.

So I realize our list of activities is lengthy, and that is just reflective of the fact we're paying attention to all the necessary aspects of the business to serve our customers. I do hope that with this update it's apparent the tremendous effort our employees our putting forward every day to continue to focus on our mission at NorthWestern of working together to deliver safe, reliable and innovative energy solutions that create value for customers, communities, employees and investors.

And with that I will open it up to your questions. Thank you.

Thank you.

(Operator Instructions)

Paul Ridzon, Keybanc.

Just a question on Colstrip -- the $4.5 million NorthWestern share -- most of that will be capitalized? Did I catch that right?

Yes.

And then, secondly, just more color on what drove the expected tax rate down to the bottom of your previous range? Is that just higher PTCs from the capacity factor?

I think just after evaluating taxes after the end of the year and certainly after we provided the guidance earlier this year, we felt that we would be able to achieve the low end of the range.

Okay, thank you very much.

(Operator Instructions)

Brian Russo, Ladenburg Thalmann.

I just want to understand the guidance revision, the $0.05 move up in the bottom top of the range? It looks like $4.5 million lower depreciation yields about $0.09 positive, and then you had $0.02 of positive weather. So it looks like that's being offset by the reduced transmission revenues associated with CS 4. Is that correct?

Brian, that's partially correct. The other component of that -- remember, the two reasons why we're increasing is the depreciation studies and the taxes, okay, knowing that we're going to be the bottom end of our range. The two takeaways, if you will -- first was some expenses. You might have noticed our operating general and administrative expenses were only up $300,000. We do expect some expenses that we didn't incur in the first half of the year to slide in the second half of the year, catch up on certain things in the transmission and distribution side of our business, some plant operation costs that we expect to be in the second half of the year. So timing, if you will, of those expenses, one of the reasons that would push down, if you will, any increase in our guidance. And the second item is we believe there's going to be an impact at the Colstrip 4 outage on our transmission revenues in the second half of the year.

Okay; and that outage is one-time, where the depreciation reduction and the tax rate is ongoing?

Correct. One thing I should also point out, Brian, in your $0.02 -- remember, the $0.02, since that was favorable to us, we take that out of our earnings to get to our adjusted GAAP. So don't take the $0.02 into our adjusted guidance. We try to take out the benefit of that weather to get back to normal weather on a going-forward basis, if that make sense.

Right, so your guidance excludes the $0.02 weather impact?

Correct.

Is there any opportunity, or are you guys contemplating raising the 50% target on your cash reserve ownership to something higher than that?

I think in that regard Bob mentioned in his prepared statements that we have a goal up to 50%, but also considering continued support, if you will, that we could also procure some of that gas for our generating units, particularly the Dave Gates.

Right, so I guess the way we should look at any future acquisitions, it could be more than that remaining 12% you need to get to 50%?

Yes --

Potentially.

Yes, Brian, we should also point out, any acquisitions might not just be perfectly to get us from that remaining percentage to 50%, too, right?

Right.

And I think, also, we've mentioned that you have a declining curve on these assets, too. So, in order to maintain at 50%, we need to continue to buy assets over time.

Okay, thank you very much.

Thank you. (Operator Instructions)

And, gentlemen, it appears we have no additional questions in the queue. I'll go ahead and turn the floor back over to Bob Rowe for any additional remarks.

I better strike while the iron is hot. It was the shortest Q&A I think we've ever had. Thank you -- which clearly reflects well on the Press Release and the disclosure. So, thank you all for your interest. We look forward to visiting with you next quarter and in between.

Thank you. And once again, ladies and gentlemen, that does conclude today's conference. As a reminder, a replay of today's program will be available after 6.30 PM this evening and last through August 24. To access the replay, please dial (888)203-1112 and enter confirmation code 185-6638. Once again, thank you for your participation. You may now disconnect.