Good morning. My name is Emma, and I will be your conference operator today. At this time, I would like to welcome everyone to the Riley Exploration Permian's fiscal third quarter 2022 conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question-and-answer session. If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you'd like to withdraw your question, again, press the star one. Thank you. Philip Riley, you may begin your conference.
Thank you, and good morning to everyone. Welcome to our fiscal third quarter 2022 conference call, covering the three-month period ending June 30, 2022. Participating on the call today are Bobby Riley, Chairman and CEO, Kevin Riley, President, and myself, Philip Riley, CFO and EVP of Strategy. Today's conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. We'll also reference certain non-GAAP measures. The reconciliations to the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I'll now turn the call over to Bobby.
Thank you, Philip, and thank you everyone for joining the call this morning. Yesterday, after the close of the market, we announced the results of our fiscal third quarter. Driven by continued organic growth paired with significantly higher realized oil and natural gas prices, we had record-setting production, net sales, and adjusted EBITDAX. In fact, year-over-year for the three months ended and the nine months ended June 30, 2022, our revenue growth was 111% and 110%, respectively. We have generated $106 million in adjusted EBITDAX for the nine months ended June 30, 2022, compared to $65 million for the same period last year. This represents a 63% year-over-year increase and is 18% higher than we generated for the entire 2021 fiscal year. To highlight a few items for fiscal third quarter.
We averaged oil production of 8,400 bbl/d , which exceeded our high end of guidance and represents an increase of 24% as compared to fiscal third quarter 2021 and 12% as compared to the fiscal second quarter 2022. We generated $45 million of adjusted EBITDAX and $44 million of operating cash flow, representing an increase of 29% and 47%, respectively, over the prior quarter. We paid dividends of $0.31 per share for a total of $6 million, representing 14 consecutive quarters of dividends with $68 million of cumulative distribution since inception.
We reported total proved reserves of 79 mmboe, which is 64% oil, with a PV-10 value of total proved and total proved developed reserves of $1.098 billion and $807 million, respectively, as of June 30th, 2022, based on NYMEX strip pricing. As we progress through the last quarter of our fiscal year, we continue to have operating and financial results exceeding both guidance and consensus expectations. With a healthy balance sheet, we remain focused on corporate opportunities, including potential acquisitions, that will help to advance our strategic growth objectives on all fronts. I will now turn the call over to Kevin to discuss in detail some of the operational results.
Thank you, Bobby, and good morning to everyone. As Bobby mentioned, we had a great quarter, not only influenced by higher realized oil and natural gas prices, but also by our continued organic growth. Riley Permian averaged daily oil sales of 8,363 bbl for the quarter, which represents a 12% quarter-over-quarter growth or 24% year-over-year growth as compared to the fiscal third quarter of 2021. The company averaged total equivalent sales of 10,176 boe/d for the same period, which represents a 4% quarter-over-quarter growth or 12% year-over-year growth as compared to the same period in 2021. As we have previously disclosed, the gas and NGL sales during February through June were impacted from an ongoing expansion underway in our midstream partners facilities.
As of July 12, the plant expansion has been completed and is providing additional takeaway capacity to our operations. In addition, the company continued efforts on its fiscal year 2022 development activity. During the three and nine months ended June 30, 2022, we brought online five gross, five net, and 12 gross, 10.8 net horizontal wells. The activity above corresponds with accrual basis capital expenditures of $34.4 million and $80.5 million for the three and nine months ended June 30, 2022. Of this, it includes $3.6 million and $11.4 million for the three and nine months ended June 30, spent on our ongoing EOR pilot.
Regarding the EOR pilot project, subsequent to the end of the quarter, all vertical injection wells have now been completed, and we're injecting water into the reservoir. Regarding inflationary pressures on capital, we estimate drilling and completion costs for recently completed wells are averaging 26% higher than equivalent well design from a year ago, owing to some inflationary pressure, but partially offset for some efficiencies we are seeing. Lease operating costs were $8.1 million or $8.71 per BOE for the three months ending June 30. This came in at the low end of our guidance, but with an 18% increase quarter-over-quarter as a result of the delayed remedial work from the second quarter due to limited workable rig availability. At this point, I will now turn the call over to Philip Riley to review our financial results.
Thank you, Kevin. After a brief overview of our financial results, I will focus on highlighting metrics not found explicitly in the financial statements or earnings release to provide more color and transparency for you. We're reporting net income for the quarter of $39 million, driven by $62 million of operating income, partially offset by a $12 million loss on derivatives and $11 million of income tax expense. Our quarterly EBITDAX of $45 million implies over a 70% margin when compared to revenue adjusted down for realized hedges. Operating cash flow closely mimics EBITDAX, which was $44 million for the quarter, or $97 million for the nine-month period. To summarize, here are a few quarter-over-quarter variance metrics.
Revenue net of hedges increased by 28%, cash costs increased by 25%, or only 15% excluding production taxes, which closely resembles oil production growth of 12%, and cash flow from operations increased by 47%. Year-over-year is obviously more dramatic. Revenue net of hedges increased by 83%, cash costs increased by 46% or only 21% excluding production taxes, which is even less than oil production growth of 24%, and cash flow from operations increased by 113%. That is the pattern you want to see. Cost increases commensurate with volume growth and bottom line cash flow increasing disproportionately more than costs. A reminder that this is all organic growth, no acquisitions, so the absolute metrics are relevant for comparison. Next, I'll offer some color on price realizations and revenues.
Quarter-over-quarter, our realized oil price improved 17% and our net realized oil price after derivatives improved a similar 16%. Our absolute volume of hedged bbl did not change quarter-over-quarter, while the percentage of hedged bbl effectively decreased from 64% in the March quarter to 57% this June quarter on account of increased production. The weighted average hedge price was unchanged. We've made no changes to our hedge position since last quarter other than the roll-off. Our hedging strategy remains unchanged from the prior quarter, with objectives to maximize upside exposure, to maintain flexibility to react to changing market environments, and to manage risk for very low prices.
Slide 15 in our investor presentation is updated for increased forecasted production guidance in the coming quarter, showing that we're approximately 50% hedged at midpoint guidance with a similar level for the subsequent quarter, then falling just under 30% down to high teens for 2023. One small detail on the upcoming quarter that differs from prior quarters, and that's that 27,000 bbl or about 7% of hedged volumes this quarter are some wider collars, floors of $45 and ceiling of $115 per barrel, which may not potentially correspond to any realized losses, at least at current spot prices, whereas prior quarters had either out of the money swaps or collars. If you exclude those collars, then we're at 47% hedged.
At some point, we may add the second half 2023 hedges, likely via some wider collars, and not until the quarters are a bit closer. Moving on to natural gas. Our net realized price increased by 90% quarter-over-quarter. Basis differential is about -$0.63, about a $0.10 higher deduction in the prior quarter. Our competition for gas based on long-haul pipes is not so much Waha as it is markets to the west, to California, hitting traffic in New Mexico or Utah, or to the north to Oklahoma. Our processing fees were just below $1.90, leading to a net of about $5 before derivatives and $1.29 after derivatives. Nat gas revenue was up 59% quarter-over-quarter on account of this price improvement, but still a bit disappointing given the curtailment.
Nat gas derivatives in turn had a disproportionately large impact given the combination of the curtailment and high settlement prices. Going forward, at least as of today, we're unlikely to hedge natural gas. Ignoring any macro fundamental view on future gas prices, the fact is that oil comprises the vast majority of our revenue, and we're not making decisions to drill wells based on gas price realizations. The silver lining here is that gas revenue net of hedges for the upcoming September quarter has the potential to double or triple, given improved processing rates and where prices are currently. While the absolute value is relatively small compared to oil revenue, the extra $1.5 million-$2 million here is helpful. For NGLs, the market price of our composite barrel garnered $50 this quarter, about $6.50 more than the prior quarter.
Relative to WTI, this quarter's 46% matched last quarter. Our overall revenue mix was skewed high towards oil, given the high prices and the nat gas dynamics. A casual observer can look at where oil prices are today relative to peaks a few months ago, or even the prior quarter average, as well as our mostly flat production guidance, and then naturally come to the conclusion that surely we'll have lower revenue this September quarter. Here's an interesting illustration to consider. If WTI averages about $86 for the remaining seven weeks of this quarter, which would be more than $17 per barrel or 16% below last quarter, then we could generate revenue net of hedges on the same level as last quarter. Here's the quick bridge. At our midpoint production guidance and that price, you lose about $12.5 million in oil revenue.
We make an incremental $2.7 million gas and NGL sales, mostly driven by increased capacity. Net-net revenue before hedges would be down by a bit less than $10 million. You look at hedges. You see volumes drop off, and at the $86 price, our oil fixed-price settlements would drop by over 40% or more than $10 million. Oil basis and nat gas hedge settlements could increase by half a million. Overall, revenue net of hedges nets out to just under $62 million, even with last quarter. Looking further out, you can appreciate our earnings potential with anticipated continued volume growth and significantly reduced negative hedge settlements, even with some backwardation. Moving on to cash flow and cash flow allocation. Cash CapEx was $37 million, or 7% higher than accrual basis CapEx.
This is reasonable in light of the prior quarter cash CapEx corresponding to only 40% of accrual. The components of the $10 million of financing cash flow includes $6 million for dividends, a $2 million credit facility pay down, a bit under $2 million of expenses tied to the refinancing of our credit facility. Quarter-end credit facility balance was $61 million. Looking ahead near term, we may pay that down by roughly $5 million over the coming four to six weeks. On capital allocation, generally, our current mindset is to continue to seek higher organic growth. Growing through the drill bit does require a higher reinvestment rate, and thus leads to a lower free cash flow conversion rate compared to lower growth companies, such as many of the large caps keeping production flat.
We recognize there's a trade-off, and that a much-used valuation metric for a lot of the investment community is a free cash flow-based yield. Though we do see our free cash flow growing in the year ahead. Year-to-date, we've allocated about 78% of cash flow from operations before working capital to cash CapEx. Roughly 15% of that CapEx can be associated with our EOR project. Excluding EOR then, we're at about 66% reinvestment rate tied to traditional E&P investment. You can compare the 66% reinvestment rate versus the 24% year-over-year oil production growth, and that's pretty good. If you exclude year-to-date hedge settlements of $60 million, you get cash flow before working capital of $159 million and a corresponding 41% reinvestment rate.
Consider that 41% rate to the 24% growth and compare those two metrics to some other companies that are less hedged. Year-to-date, we've distributed 83% of free cash flow in the form of dividends. A few final thoughts here on the macro environment and ESG. Oil and gas continues to be the number one primary energy source globally by a long shot. With oil alone, Riley Permian is just a small participant in a $3.5 trillion per year global market. We've witnessed a structural downward shift in investment in oil and gas over the past few years, partly in response to shareholder priorities for mostly domestic companies, but more broadly in response to growing ESG mandates and shifting of capital allocation globally. We are believers in the many positive aspects that ESG can bring to corporate governance and stewardship.
We balance our objectives of producing low-cost energy with our commitment to looking after the environment, our employees, and our shareholders. We're also seeing a refreshed welcome dialogue this year reexamining ESG based on perspective and context. In the last three years, we've experienced foreign supply chain breakdowns, leading to rethinking of offshoring, manufacturing, and labor, as well as dramatically heightened geopolitical tensions and global energy crises across continents. In this context, providing basic energy needs from responsible sources should be valued. At Riley Permian, we are a U.S. company with 100% domestic operations, 100% domestic staff, responsibly producing 100% domestic natural resources that are among the highest demanded products in the world, and which help clothe, feed, shelter, warm, cool, and transport our global population. Thank you, and I'll turn it back to Kevin now.
Thank you, Philip. I will now give guidance for the company's activity for our fiscal fourth quarter and the full fiscal year of 2022. For the fiscal fourth quarter, we forecast accrued basis capital expenditures of $28 million-$34 million. Associated with those forecasted costs, the company estimates drilling four gross and 3.2 net, completing seven gross, four net, and turning to production seven gross, four net horizontal wells, along with other customary capital project expenditures, including prep work for our fiscal year 2023 development program, along with $4 million-$6 million for our EOR pilot project. We forecast fiscal fourth quarter 2022 oil production to average 8,200-8,600 bbl/d, and total equivalent production to average 11,100-11,600 boe/d.
We anticipate fiscal fourth quarter LOE of approximately $8 million-$10 million, with the low end corresponding to actual fiscal third quarter results and the high end accounting for costs associated with the increased production volumes and continued inflationary pressures. In addition, we are forecasting cash G&A expenses of approximately $4.1 million-$4.7 million. We have modest upward revisions for our full-year fiscal year 2022 accrued basis capital expenditures of $109 million-$115 million, up from previously provided estimates of $102 million-$111 million. For full-year fiscal year 2022, we are forecasting an annual total wells completed and brought online of 19 gross, 15 net wells. We anticipate full-year accrued basis EOR-related capital expenditures to total approximately $16 million-$18 million.
Approximately $4 million of what was previously estimated accrued basis capital expenditures for our EOR program are now anticipated to incur in fiscal year 2023. The company plans to begin CO2 injection during calendar fourth quarter 2022. Based on our current estimates, we forecast full-year fiscal year 2022 oil production to average 7,800-7,900 bbl/d, representing 22%-24% growth from fiscal year 2021 average oil production. In addition, we forecast full-year fiscal year 2022 total equivalent production to average 10,300-10,400 boe/d. With that, I will now turn the call over to Bobby for closing remarks.
Thank you, Kevin. Again, thank you to everyone for joining us today for our third fiscal quarter call. As we look forward, our team is taking several steps to navigate through inflationary pressure for services and products, including securing materials and services well ahead of scheduled activity plans. We remain focused on a disciplined model of low leverage, production growth, and return of capital through dividends to our shareholders. Thank you again for your support. Operator, you may now open it up for questions.
Thank you. As a reminder, if you would like to ask a question, press star then the number one on your telephone keypad. We'll pause for just a moment to compile the Q&A roster. Your first question comes from the line of Bertrand Donnes with Truist Securities. Your line is now open.
Morning, guys. You kind of touched on it in the prepared remarks, but I was just looking for a little more color on the shareholder return front. You know, you're at about 5% with the base dividend. Is the plan to just grow that as cash flows grow, or are you thinking about layering in other options? Or are you maybe at the other train of thought, where maybe some additional organic growth or external growth is really the best use of cash?
Yeah. Thank you, Bertrand. It's Philip. It's a fair question. For now, I think we're focused on the dividend. We've talked about different measures. It's our goal to grow the dividend annually. We can't speak exactly as to what will happen until our board approves something. You know, if we want to approve something annually, at this point, we just paid our fourth dividend at the same level. We're hopeful we can raise that in the future. General goal is to raise that high single digits, close to 10% or so. In addition to that, at the moment, we see benefit of paying down debt, building liquidity a bit. It gives us more optionality for pursuing acquisitions and such if we should see something attractive, just given, you know, capital availability in the market and such.
We're mindful of using too much debt for something, and so it's nice to have the full availability, even though our current leverage is so low. We have talked about different types of different return programs. Obviously, we watch the market. We see others do buybacks, for example. We've discussed that with our board and understand some of the trade-offs, benefits, and drawbacks there. You know, one note is that we do have a relatively lower slope, and we're working to improve that. At the same time, we can recognize the potential benefits of supporting a stock price during times of volatility. We'll keep looking at it.
You know, final thing I'd say is that the, you know, free cash flow was somewhat suppressed this year with a bit higher spending with the EOR projects, the, you know, the hedge settlements. Going forward, we should have more, you know, based on what we're seeing in our forecasts and even with some degradation. That should give us some more options.
That the note on high single digit growth, is that based on maybe the company's outlook on where the m arkets are going on a macro sense, or is that more about where you think, you know, next year Riley cash flows are?
I think it supports our long-term vision of what we can achieve and have as a sustainable dividend. We see, you know, we haven't disclosed or even formalized even internally a 2023 budget, but it's fair to say that we wanna continue the type of growth that we've achieved to date. Even with the overlay of some of the backwardation per my little illustration there, the trade-off with the roll-off of the hedges can still be a net positive. We do see cash flow and such growing quite a bit more than high single digits, overall EBITDA and such growing quite a bit more than that. Yet on the dividend, we, you know, we wanna have something that we can support long term through some volatility.
That's perfect. My next question was just kind of on that topic. The hedging slide you assume just for the percentages for the presentation, 15% growth year-over-year. I just wanted to understand, is that just for simplicity you know, or is that to kind of give a baseline growth and does that have some assumed commodity strip pricing?
You know, probably both on the first part of your question. You know, just to clarify that first column there with the 50% does tie to our guidance. There's 0% or a very small amount of growth there, and then the subsequent quarters do assume a 15%, year-over-year growth there. You know, it's indicative of where we wanna go, if not more. Just to put that into context of, you know, thinking about volumes, I think it's a fair amount. It doesn't have an overlay with the commodity prices. It's just a pure volume exercise there.
That's fine. That makes sense. I'll hop back in the queue. Thanks, guys.
Your next question comes from the line of Noel Parks with Tuohy Brothers. Your line is now open.
Hi, good morning.
Good morning.
Morning.
I just have a couple basic ones. Just thoughts at this point about what you might be looking at for rig rates going forward. Just curious for the class of rigs that you use, are you seeing the vendors sort of avoiding, you know, you locking in a longer contract, you know, out of hopes that they'll see sort of upside for spot pricing? Or instead are they looking to kinda look into a longer commitment these days?
For us, we've done well in being able to secure rigs for, you know, a good part of our fiscal year 2023 program, so far. That puts us through probably the spring of 2023. Then we see the availability or the option to extend and add on, with the vendors that we've chosen to use so far. I think that, you know, a lot of the guys in our area are just trying to look at, you know, utilization and consistency versus, the volatility that comes with the spot price.
Gotcha. Okay, great. Anything on the materials front you could talk about?
Materials are still tight. We were fortunate to have locked up a lot of the raw materials that we need for our program, steel, sand, the rigs and some of the service crews, and continuing to look to add to that list. It is a very tight market and to be able to accelerate quickly, it would be very challenging right now without plans well ahead, securing the items that are in tight supply.
Sure. Pretty consistent with what we're hearing across basins, I'd say. I guess just as you look at longer term investments, for example, EOR, the EOR project and you know, how that might extend over time, for example, into carbon capture. Has the interest rate environment made you change sort of your scenarios that you're modeling for, just in terms of looking at the cost of capital and then rates of return?
You know, it's a fair question. I think given where our leverage is, it's such a small component of our overall enterprise value that we focus primarily on cost of equity capital. We consider that to be quite a bit higher than debt. Debt has gone up a bit. You know, we are fortunate we've got some interest rate hedges in place that are in the money and helping us out, that are a bit embedded there that you don't see too often. Going forward, though, with the growth price and free cash flow profile that we see, we frankly see leverage continuing to decline on an absolute basis. It's just a pretty small number overall. You know, it can influence our thinking on, say, a debt-financed acquisition.
The type of growth that we're looking at is primarily driven by a cash flow. We don't see needing to dip into, you know, debt to do that materially. You know, on the carbon capture front, you know, very briefly, most of what we're looking at is more of a partnership model where we might do a fee for service, and Riley Permian is not using its balance sheet to, say, buy the capture equipment. It might have a return that is lower than what we consider our, you know, cost of capital to be, but rather just take fees for taking and using or storing the CO2.
Got it. Great. Thanks a lot.
Thank you.
Your next question comes from the line of Jeff Robertson with Water Tower Research. Your line is now open.
Thank you. Good morning. Kevin, as you think about fiscal year 2023 activity levels, would you expect at this point, given where costs are and where commodity prices are, to carry on the activity levels that you have forecast for the fourth quarter of 2022?
Yeah, I would expect, you know, to continue to operate at a pace very similar to the year that we're in, especially as, you know, Philip alluded to, with hedges continuing to roll off, we'll have more cash flow. We wanna continue to grow at a pace that, you know, we've grown over the last four or five years. Overall, I mean, D&C costs have gone up around 26% and oil prices have nearly doubled. It's not 1:1. We're still increasing our returns and growing the company. I don't see us slowing down at this point. We have a good return on the asset we have.
Kevin, do you have a feel yet for what 2023 costs might look like as you procure some of the equipment that you'll need for the fiscal year 2023 capital program compared to the 2022 increase you're seeing now?
I think that, you know, we've probably seen a lot of the increases already, what we realized in the last quarter or two. As we go forward, we hope to either be able to arrest further inflation or possibly lower the costs through some of the efficiencies we are continuing to gain. For instance, sand, we're starting to self-source sand, so that'll be a saving. Just becoming more efficient in our operations and making sure everything is done to the right degree versus over-fracking or over-drilling a well. Hopefully we are at the peak of that. I can't say that with certainty, but we hope that's the case.
On the gas processing capacity, how much of an impact does that have on your fourth quarter production estimate of 11.1-11.6 mboe/d? In other words, if you didn't have constraints, do you have a feel for what that number might be, what the production number range might be?
For fourth quarter, I think we have it baked in that we're going to produce or sell most of which we produce. As stated, we started selling at our MDQ level or higher in July, and the plant expansion was completed on July 12th, formally announced completed. I think that we are on target to meet our production range or guidance. If not, beat it, we're still just trying to make sure we don't have any surprises with the new plant. So far everything is working smoothly, and we're excited to see the results.
Okay. Thank you very much.
Your next question comes from Sandra Vandenbrink with Tokai Capital Corp. Your line is now open.
Thank you. Good morning, gentlemen. First, I'd like to congratulate you on the successful quarter, and thank you for your continued hard work and focus. My question: Could you speak to where you are with the CO2 flooding for enhanced oil recovery?
Good morning, Sandra. This is Bobby.
Morning. Hi, Bobby.
Yeah, as we kind of said in there, all six of our initial plant injection wells are now online. We are injecting water at a slightly higher rate than we actually originally modeled, which means, and that's a good thing for us. We are just starting to see some communication, not breakthrough or anything like that, but some communication between a few of the wells, so things are on schedule there. We plan to start injecting CO2 in the fourth calendar quarter, which, you know, we would expect to see some response relatively soon, but it's still too early to make an exact prediction. Things are online. You know, I've chatted with the team this morning, and they're very happy with the response that we're seeing and the way the operation is going.
Great. Look forward to hearing some more results.
Your next question comes from the line of Richard Dearnley with Longport Partners. Your line is now open.
Good morning. To follow that last question, does the new tax credits, which seem to be, you know, quite, you know, a large increase, has that meaningfully changed the dialogue on CO2? I can take that. This is Philip. You know, we're pleased overall to see that go through. It is, as you say, it's a meaningful increase for EOR storage. It's about $25 incremental. For permanent it's $35. Both correspond about a 70% increase. You know, this industry for equipment is not insulated from inflation, just like the rest of the world, they're suffering from that. Costs for equipment have gone up, as well, maybe 40%.
We're hopeful that just like our financial performance, that the revenue is still outpacing the cost increase. There is, you know, there is some trade-off there. You know, there are other aspects of it that are helpful. You've got five years of direct pay, and you've also got a reduction in the minimum size threshold from, say, 100,000 tons down to way down to 12,000 or so. You know, for the groups that we're talking to, we are, you know, we're processing all of this. We've got potentially a tax appetite in the future. We've talked to, you know, groups that are more financial types that could help us monetize that tax credit. Some of this does make it more interesting.
You know, what I can say is we're working hard on it, and you know, we're excited about it. The EOR, especially the credit, what that could represent for something for us would be really meaningful. You know, we've got this fully permitted project. It's ready to go. It doesn't have the timing delays like a Class VI well might have for the permanent storage. We see exciting opportunity to potentially start with something there and then later in its life, potentially shift to permanent.
Good. Thank you very much.
As a reminder, if you would like to ask a question, press star, then the number one on your telephone keypad. Your next question comes from the line of Jeff Robertson with Water Tower Research. Your line is now open.
Thanks. Philip, a follow-up on the EOR. As you start to inject CO2 in the fourth quarter of calendar 2022, while you're injecting them before you get response, will the EOR cost or the CO2 cost rather be capitalized as a capital expense, and then it reverts to an operating expense when you start producing? Or is it, is it going to be an operating expense while you're injecting?
No. Yeah, you're right. The former is how we're thinking about it. It's capitalized towards the beginning, and then at some point we make a determination, and we shift it to operating.
Okay.
We'll try to be clear with that going forward. Yeah, that's right. As we start talking next year, we'll try to give some clear guidance as that can be a little bit confusing.
Thank you.
There are no further questions at this time. This concludes today's Q&A and today's conference call. Thank you so much for attending. You may now disconnect.