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Text: We've revised our full-year 2021 estimate for DCF and EBITDA substantially upward.
Steve, Kim, and David will explain the underpinnings of that change.
We also increased our dividend to an annualized rate of $1.08 per share as we promised when we released our original outlook for 2021 back in December.
In my judgment, this increase is an indicator of the significant parts of our corporate financial policy.
First, it shows we are intent on returning value to our shareholders.
Second, it demonstrates the consistent strength of our cash flow.
To put this in perspective, this is the fourth consecutive annual increase in our dividend since 2017, when we were paying an annual dividend of $0.50 per share.
And we have accomplished that while maintaining a real focus on our balance sheet, having reduced our debt from its peak of almost $43 billion in 2015 to $30.7 billion today, a decrease of over $12 billion, quite an improvement.
Now we're doing all this while continuing to pursue opportunities with our natural gas assets to firm up deliverability and supply to our customers, opportunities that were highlighted by the recent winter storm in Texas, and also while examining opportunities in the energy transition effort.
At Kinder Morgan, we remain guided by what we believe is a sound corporate philosophy, fund our capital needs internally, maintain a healthy balance sheet, and return excess cash to our shareholders through dividend increases and opportunistic share repurchases.
We think this is a recipe for long-term financial success for KMI and its shareholders.
I'll focus on our performance during Winter Storm Uri, which is what drove our financial results in the quarter.
So starting with the performance during the February winter storm.
We were prepared, and that preparation served us well.
Our previous investments in our assets, particularly on our gas storage assets, were a huge help.
We were on maximum withdrawal for days at several of our fields.
Also helpful were our investments in backup generators at key compressor stations on our system.
Another real key for us was our team.
Our operations team deployed in advance to keep our facilities running and quickly repair them if they went down.
We deployed additional generators and tested our generators before the storm got here.
Our people were at locations that are normally automated, and they were there in the bitter cold, and undoubtedly, many of them have their own families at home without power and water.
Our team went to key compressor stations, storage facilities, and delivery points to keep gas flowing, including a key delivery point to the city of Austin.
Our people kept us going.
Our investments and especially our team winterized us against a terrible storm.
We also purchased additional gas, some at very high prevailing prices, to serve power plants and gas utilities.
The result of all this was that we enabled our wholesale customers to serve needs that would have otherwise gone unmet, mitigating the tragedy that too many Texans endured.
We performed well operationally and commercially across our entire gas network, but our financial performance was especially strong in our Texas intrastate pipeline and storage network.
And as I'll mention in a minute, in our CO2 business for reasons I'll explain.
A key difference between our Texas intrastate system and our interstate gas pipeline systems is that we have a purchase and sale business in Texas, supported by high deliverability storage assets.
In contrast, our interstate pipelines are nearly exclusively selling unbundled transportation and storage services.
We do that in Texas, too, but we also have a purchase and sale business.
That business is generally done with reference to an index price.
For example, we sell gas at the Houston Ship Channel index plus something and buy at Houston Ship Channel minus something.
In normal circumstances, we're effectively getting a transport margin on our purchases and sales and using our proprietary storage to extract margin from price differences across time periods.
When prices are in a normal range, this is a very stable business.
And we view our Texas intrastates as roughly 80% or so take-or-pay.
In February, supply and demand conditions caused prices to go up by more than 100x and back down by the same order of magnitude over the course of a week.
Market volatility like we experienced that week reveals the value of reliable pipeline and storage assets and a reliable operations team.
It reveals the value of having gas in storage and previous purchase arrangements in place.
It also reveals the value of preparation in such circumstances in which supply and demand conditions causing prices to go up by more than 100 times, we were able to perform well financially, as well as operationally.
Many of our additional sales, whether as a result of higher takes under our existing contracts or incremental sales that we were able to do during that week, took place at prevailing market prices.
which during that week at the Houston Ship Channel, range from $180 MMBtu to $400 versus $3 earlier in the same month.
What does this mean for our business longer term?
We transact with sophisticated customers who have choices.
One of those choices is to purchase firm services from us on a long-term basis, and many of them do.
While we view the events in our financial results as largely nonrecurring, we are already pursuing more long-term firm capacity sales and some associated capital investments that will help our customers to be even better positioned for future extreme weather and create incremental value for Kinder Morgan.
There is substantial interest in our services following the storm, which should help us in our base business and in new origination.
The results could be long-term, additional, and more consistent earnings and investment without the extraordinary and rare gain that we experienced in the first quarter.
The big lesson that should be taken away is that an appropriate amount of contracting for firm deliverability should be in everyone's portfolio.
And February's event reveals the value of storage and firm transport capacity.
And we would hope that any changes made in the market structure would adequately compensate and incent parties to do so.
I mentioned our CO2 business also.
This is a bit of a different effect.
That's our biggest power consuming business in the state of Texas.
Our power contract with our provider enables us to shed load and be compensated at the prevailing power prices.
When they started to see where power prices were headed, Jesse Arenivas and his team started looking at shedding load.
So we shut down oil production and shed the load back into the market, where it could be allocated to higher priority human needs.
The contract work, as designed and particularly with prices as high as $9,000 a megawatt hour, we earned a substantial financial benefit, while letting those megawatts be made available to serve human needs.
Also notable, for the longer term, Jesse and his team were able to restore production quickly and fully following the storm.
That's a great accomplishment.
They had some practice when oil prices went drastically down last year, and we've gotten better at it since then.
Our flexibility is greater.
This is great flexibility that we've now built into a part of our business that consumes about 340 megawatts in the state of Texas.
So good flexibility to have in the power market in the state of Texas.
So we're very proud of our whole team's performance, but we have lessons to learn too.
And we'll use those lessons to get even better at severe weather performance for us and for our customers.
So what will we do with the proceeds?
Initially, of course, it's a reduction to our net debt.
But as we repeated many times, our financial principles remain the same.
First, maintain a strong balance sheet.
Second, we maintain our capital discipline through our return criteria, a good track record of execution, and by self-funding our investments.
And as I mentioned, we may see some incremental investment opportunities as a result of the storm.
We don't expect those to be significant for 2021.
Finally, we are returning value to our shareholders with a dividend increase that Rich mentioned.
It's a well-covered dividend.
And our approach to share repurchases remains exactly the same.
We'll be selective, not programmatic.
We'll base our decisions on the returns versus the alternative uses for the cash that we generate, including projects or assets.
So strong balance sheet, capital and cost discipline, returning value to shareholders.
Those are our principles.
We put together a team with financial, commercial, and engineering talent to focus on analyzing and quantifying opportunities for additional assets and service offerings tailored to the ongoing energy transition, including things like renewable natural gas and carbon capture and sequestration.
This group reports to Jesse Arenivas, who continues as president of our CO2 business and is headed by Anthony Ashley, who previously served as treasurer and vice president of investor relations.
While still in our early days for this effort, they've already identified and are working on a number of specific opportunities.
Also, as I said last time, our business units continue to focus on the energy transition opportunities that fit in with their operations, such as midstream services for renewable diesel and including our -- using our gas transportation and storage services to support renewable power.
We are also marketing our low methane emissions performance as responsibly produced and transported natural gas.
That's a good synergy between our ESG performance, our low methane emissions, and our commercial opportunities.
We participated in our first one of these transactions with Colorado Springs Utilities, which they announced in the first quarter.
And we're working on another as we speak.
We believe the winners in our sector will have strong balance sheets, low-cost operations that are reliable, safe, and environmentally sound, and the ability to get things done in difficult circumstances.
We're proud of our team and our culture.
And as always, we'll be prepared to meet the challenges and opportunities to come.
First, I'm going to go through the business fundamentals for the quarter, and then I'll talk at a very high level about our full-year forecast.
Starting with the natural gas fundamentals.
Transport volumes were down about 3% or approximately 1.1 million dekatherms per day versus the first quarter of '20.
And that was driven primarily by declines in Rockies production, increase in transportation alternatives, and lower production out of the Permian, those two things impacting our volumes on EPNG and contract expiration on our joint venture pipe coming out of the Fayetteville.
These declines were partially offset by higher volumes, which were driven by increased deliveries to LNG export facilities, winter weather in the northeast, and the PHP in service.
Physical deliveries to LNG facilities off of our pipeline averaged approximately 4.7 million dekatherms per day.
That's greater than a 25% increase versus the first quarter of 2020.
LNG volumes were down from the approximately 5 million dekatherms per day in the fourth quarter of '20.
And that was due to the impact of Winter Storm Uri and some coastal fog in February.
During the storm, total LNG exports dropped to under 2 million dekatherms per day.
In the first quarter, Kinder Morgan pipes moved approximately 47% of the volume going to LNG export facilities.
Exports to Mexico on our pipes were up about 3% when compared to the first quarter of '20.
Our share of Mexico deliveries in the first quarter ran about 55%.
Deliveries to power plants, they were down due to higher natural gas prices.
Deliveries to LDCs were up due to colder weather.
One, on our natural gas gathering volumes, they were down about 25% in the quarter compared to the first quarter of '20.
But for gathering volumes, I think the more informative comparison is the sequential quarter.
So compared to the fourth-quarter volumes, first-quarter volumes were down about 11%.
Approximately two-thirds of that 11% reduction are related to KinderHawk, which is our gathering asset in the Haynesville.
But given that there are 45 rigs deployed in that basin, we expect that our volumes will increase sequentially each quarter for the balance of the year, although it will be a little bit slower than what we've budgeted.
Eagle Ford volumes were also down versus the fourth quarter, and we expect that those will be down versus our budget.
The Eagle Ford remains a very tough market, given the oversupply of takeaway options.
On the positive side, we expect volumes in the Bakken and Altamont to be on plan or better for the year.
In our products pipeline segment, refined products volumes were down about 10% for the quarter versus the first quarter of 2020.
And that's just the result of the continued pandemic impact.
Gasoline volumes were up 6% versus the first quarter of '20.
That's an improvement from the fourth quarter when they were off about 10% versus the fourth quarter of 2019.
Jet volumes remain weak off about 29%, but that's a big improvement from the fourth quarter when they were off 47% versus the fourth quarter of '20.
And diesel volumes were up 6%, and that's relatively flat to the percentage in the fourth quarter.
Total volumes moving through our pipes did improve each month during the quarter.
March volumes were up slightly versus 2020, and they were down about 6% versus 2019.
Currently, we're forecasting refined products to be down versus our plan, and I'll go through that a little bit later in my comments.
Crude and condensate volumes were down about 28% in the quarter versus the first quarter of 2020.
Sequentially, they were up 2%.
Our terminals business fundamentals have been impacted by two events: the winter storm and the continued impact of the pandemic.
The winter storm was short lived, with the impact limited to the first quarter.
The pandemic is lingering, and it continues to impact our petroleum product volumes as well as demand for our Jones Act tankers.
However, as we've mentioned in prior quarters, the impact of reduced petroleum product demand on our tankage is more muted than in our product pipeline, given the fixed take-or-pay contracts for tank capacity.
Our liquids utilization percentage, which reflects the tanks that we have under contract remains high at 95%.
If you exclude tanks out of service for required inspection, utilization is about 98%.
On the tankers, we have a number of ships that have contract expirations this year, and the market is relatively weak, given the weakness in refined product volumes.
The reduction in crude oil production and the tightening WTI Brent spread also impacts this market, but to a much lesser extent, given a smaller percentage of the fleet engaged in that service.
We expect this market to improve with the recovery in petroleum product demand.
But that may take in for later this year because charter activity tends to lag underlying supply and demand fundamentals.
Now the CO2 segment was up in the quarter due to our decision to curtail production and deliver power back to the grid that Steve mentioned.
Excluding the storm impact, oil production was down approximately 15%.
CO2 sales volumes were down 26%.
Our net realized oil price was down about $3.50 per barrel.
However, compared to our budget, we're currently anticipating the oil volumes, CO2 volumes and net realized oil price will exceed budget for the year.
Now let me give you a very high-level update on our full-year forecast.
As we said in the release, we're currently projecting full-year DCF of $5.1 billion to $5.3 billion versus our budget of $4.45 billion.
We estimate that the Uri impact, and this is across all of our segments, was roughly worst-season hand grenades $1 billion, leaving a variance, again, very roughly, of $200 million to $350 million versus our budget.
I know $200 million doesn't add up perfectly, but that's because these are very large rounded numbers.
Let me start with the $200 million variance.
We estimate that sustaining capex will be approximately $75 million higher than our budget due to the decision to replace some pipe in rural South Texas as opposed to continuing to spend money running inspection tools and repairing the pipe.
We were also able to obtain the pipe at very attractive pricing.
What I'll classify as pandemic-related impacts is roughly $80 million, and that includes weaker petroleum products volumes and lower renewal rates on Jones Act tankers.
Those two items explain about 75% of the variance, but there are a lot of other moving parts.
A couple of the other larger items include lower gathering volumes, primarily in the Eagle Ford, and the impact on DCF of a Ruby impairment.
Those two items are roughly offset by positive performance in the CO2 segment, from higher CO2 and oil volumes and price.
Finally, the sale of our 12.5% interest on NGPL creates a negative variance versus our budget.
The difference in that low and the high end of the guidance range primarily relates to assumptions on petroleum products volumes, Jones Act tanker renewals, natural gas GMP volumes, and the resolution of certain Uri contractual disputes.
I think it's obvious, but just in case, the lower end of the guidance range assumes a more conservative outcome on these items.
For example, The high end of the guidance range assumes petroleum products volume 3% below plan for the balance of the year versus the low end of the guidance assumes they're about 5% below plan for the balance of the year.
So for the first quarter of 2021, as Rich mentioned, we are declaring a dividend of $0.27 per share, which is 3% up from last quarter.
Now looking at the financial performance for the first quarter of this year versus the first quarter of last year, we generated revenues of $5.2 billion, up $2.1 billion.
We had partial offsets in our -- a partial offset in our cost of sales with an increase of $1.3 billion there.
So our gross margin was up $759 million, mostly driven by our strong performance during the winter storm.
Our O&M costs declined as a result of the CO2 segment power load shed that Steve walked through.
And that's the main item in the $106 million favorable O&M amount.
In the first quarter of 2020, we also took impairments in our CO2 segment of $950 million, which explains most of the $975 million favorable in the item -- the line item called gain and loss on divestitures and impairments.
This past quarter, we wrote off the value of our Ruby subordinated note, which was a reduction of $117 million in the earnings from equity investments.
And that was driven by greater uncertainty regarding the recoverability of that note receivable.
We also reflected a $206 million gain on the sale of a partial interest in NGPL, and that appears in the other net line item.
So overall, we generated net income of $0.62 per share, which is very favorable versus the $0.14 loss in the first quarter of 2020.
On an adjusted earnings per share basis, and then that's where we show earnings per share before certain items, we generated $0.60 per share versus $0.24 per share a year ago.
Moving to our segment EBDA and distributable cash flow performance.
Our natural gas segment was up $915 million for the quarter, mostly explained by favorable intrastate margins as well as increased revenue on our Tennessee Gas Pipeline, both as a result of the February winter storm performance.
We also had favorable contributions from PHP, which was placed in service at the beginning of the year.
And these are all partially offset by lower contributions from our FEP pipeline resulting from the 2020 contract rollovers.
Product segment was down $10 million, driven by lower refined product volumes on SFPP, lower crude oil volumes on KMCC, and lower recontracting rates at HH, partially offset by greater contributions from our transmix business.
Our terminal segment was down $30 million.
And that's really refined product volumes due to continued pandemic-related demand impacts, as well as winter storm-related demand impacts.
As has been mentioned, our Jones Act tanker contributions were also down lower due to the lower fleet utilization resulting from the pandemic-related market weakness.
Storm-related refinery outages also drove decreased contributions from our pet coke facilities.
And these were all somewhat offset by our expansion project contributions.
Our CO2 segment was up $116 million this quarter versus a year ago.
Again, due to the shedding load to deliver power to the grid.
And partially offset by lower -- and that was partially offset by lower crude and CO2 volumes versus Q1 2020 and lower realized crude prices versus Q1 2020.
Our G&A at corporate and corporate charges were higher by $8 million.
And there we had lower capitalized overhead expenses, partially offset by our organizational efficiency savings.
JV depreciation, we had less JV DD&A from our Ruby investment there.
And that's after Ruby recognized an entity-level asset impairment in the quarter resulting in lower depreciation.
That brings us to adjusted EBITDA, which was $966 million, or 52% higher than Q1 2020.
Moving down below EBITDA.
Interest expense was favorable by $52 million.
They're lower LIBOR rates benefiting our interest rate swaps drove nice favorability as well as a lower debt balance and lower rates on our long-term debt.
For the quarter, sustaining capital was favorable by $34 million, and that was driven by lower terminals and natural gas segment capex.
But all of that is timing, and we expect to spend more sustaining capital for the full year versus 2020.
In other, we had some lower pension cash contributions versus a year ago.
This year, we have a little bit more back-end loaded cash contributions to our pension plan versus more equally spread quarterly contributions last year.
So our total DCF was $2.329 billion and was up $1.068 billion, or 85%.
And our DCF per share was $1.02, up $0.47 from last year's $0.55 per share.
Moving on to the balance sheet.
We ended the quarter with net debt to adjusted EBITDA of 3.9 times, down nicely from the 4.6 times at year-end.
And we currently project to end 2021 at 3.9 times to 4.0 times, and that's consistent with the ranges that Kim walked through.
And that's largely a result of the largely nonrecurring winter storm benefits contributing to our EBITDA, but it also is a result of lower-than-budgeted debt balance due to the greater than budgeted cash flow.
Our longer-term leverage target of 4.5 times has not changed.
We also have a very favorable liquidity position.
We ended the quarter with almost $1.4 billion of cash on hand and only have $500 million of consolidated debt maturing for the rest of the year.
So our net debt, which includes our cash on hand, ended the quarter at $30.7 billion, down $1.348 billion for the year -- from the year.
And now, our net debt has declined by $12.1 billion or almost 30% since Q1 of 2015, as Rich mentioned, but is worth reiterating.
So our quarter change to reconcile the change in debt of $1.35 billion for the quarter.
We generated $2.329 billion in DCF.
We paid dividends of $600 million.
We made $200 million of contributions to our growth projects as well as to JVs.
We received $413 million from the NGPL sale, and we had $600 million of -- approximately $600 million of working capital uses, primarily interest expense payments, AR increases, and a rate case settlement on SFPP.
That explains the majority of the net debt change and completes our first-quarter financial review.

user
kinder morgan q1 earnings per share $0.62.
reases dividend 3 percent and raises 2021 guidance.
q1 earnings per share $0.62.
approved a cash dividend of $0.27 per share for q1.
bulk of improvement in q1 net income and dcf is due to strong performance of natural gas pipelines segment.
in q1, system deliverability and resiliency was also enhanced by investments in expansion projects and asset maintenance in texas.
qtrly adjusted earnings per share $0.60.
kmi also now expects to end 2021 with a net debt-to-adjusted ebitda ratio in a range of 3.9 to 4.0.
as of march 31, 2021, had over $3.9 billion of borrowing capacity under $4 billion credit facility, over $1.3 billion in cash, equivalents.
kinder morgan - believe borrowing capacity, current cash on hand, and cash from operations are more than adequate to manage cash requirements, through 2021.

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