Kinder Morgan Inc - Class P (KMI) — Q1 2015 Earnings Call Transcript

Thank you, Sharon and welcome to our first quarter analyst call. As usual, we’ll be making statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. I'll give an overview of the quarter, then Steve Kean, our Chief Operating Officer, will talk about the performance of our five business segments and give you an update on our backlog of expansion projects. And then our CFO, Kim Dang, will explain the financial results in detail, and then we'll take any questions that you might have. Our Board today voted to increase the dividend for the first quarter to $0.48 or $1.92 annualized. That’s up 14% from the first quarter of 2014 when we paid a dividend of $0.42 per share. And it’s a 7% increase from the $0.45 we paid for the fourth quarter of 2014. This is consistent with our announced intention of declaring $2 per share in dividends for 2015, the full year of 2015, which would be a 15% increase over full-year 2014. We are on track to do just that. We also continue to project growth in that dividend of 10% per year off that $2 base out through 2020. Our DCF per share was $0.58 for the first quarter, which equates to coverage in excess of our dividend of $206 million. Any comparison with the first quarter of 2014 is a little bit like comparing apples to oranges, because of course we didn’t roll up KMP, KMR, and EPB until the fourth quarter of 2014. That said, the simplest comparison is this: In the first quarter of 2014, we had 1.036 billion shares outstanding. We had DCF of $0.55 per share. We declared a dividend of $0.42 per share, which resulted in excess coverage of approximately $138 million. This quarter we had 2.159 billion shares outstanding. We had DCF of $0.58 per share. We declared a dividend of $0.48 per share, and that resulted in excess coverage of about $206 million. So we more than doubled the number of shares, we increased the dividend by 14% and we still substantially increased our excess coverage. All in an environment of dramatically lower commodity prices. For example, our average realized oil price per barrel in our CO2 segment was $72.62 in the first quarter of 2015 versus $91.89 in the same quarter a year ago. And the average Henry Hub price for natural gas was $2.98 in the first quarter of 2015 versus $4.94 in the first quarter of 2014. This demonstrates that our enormous footprint and our diversified set of mostly fee-based assets can produce very good results even in times of tumultuous market conditions. Notwithstanding the lower commodity prices, we experienced good volume growth in most of our businesses. For example, our natural gas transportation volumes were up 6%, our refined products volumes were up 5.6%. Our condensate volumes more than tripled. Our net oil production in our CO2 segment was up 9%. And our liquids throughput in our Terminals group was up 23%. In short, we expect to continue to perform well in 2015, pay our dividend as originally targeted at $2 with substantial excess coverage as we’ve demonstrated this quarter. I believe we are setting the table for years of good growth. And with that, I’ll turn it over to Steve.

Thanks, Rich. I’ll provide an update on the project backlog, discuss two projects not yet in the backlog, and highlight operational commercial insights from the segments. Since our January update, the backlog has seen a slight decrease of about $200 million on a comparable basis. We added $1.1 billion in new investments to the backlog, with 40% coming from the high probability portion of the Hiland backlog. The remainder mainly consists of additional expansions for gas pipelines and terminals. During the quarter, we implemented nearly $400 million worth of projects, with half attributed to the startup of the first condensate splitter from our two-splitter project in the Houston Ship Channel. Even with the $400 million worth of projects put into service, we grew the backlog by $700 million. However, this growth was offset by the removal of approximately $900 million, primarily from our CO2 business. The economic viability of new CO2 source developments is challenged in the current commodity price environment, so we've postponed developments like the St. John's field and Lobos pipeline from the backlog. That said, we continue to experience strong demand for the expansion of our midstream pipeline and terminal businesses despite lower commodity prices. We've also adjusted our methodology to include overhead, and our backlog now stands at $18.3 billion, factoring in capitalized overhead as it is part of our investment decision-making. The figures I mentioned are compared to last quarter. Two projects we haven’t added to the backlog yet include Northeast Direct, where we’ve made significant progress and received substantial commitments from LDC customers, totaling over 550 a day. There's a compelling economic need for this project, given the increased gas capacity demand in the Northeast following two challenging winters. The surge in energy costs during this period indicates that this project, estimated at around $5 billion, is necessary. The proximity of high and low gas prices in North America reinforces the need for a new pipeline, and we are close to securing more commitments from the power sector, although this project hasn't entered the backlog yet. The second project, UMTP, proposes converting an existing Tennessee gas pipeline to NGL service, enabling better access for producers to markets, including Mont Belvieu and potentially export water. We've revised our offering to market producers a batched system, providing them with more transport options. Interest has been shown, but we haven't received any agreements yet, so it's not in the backlog. We also submitted an abandonment request for the TGP line to facilitate its conversion to NGL service. Regarding segment performance, earnings before DD&A for the gas pipeline segment reached $1.087 billion, a year-over-year increase of 1%. This was driven by the addition of the Hiland assets, strong EPNG performance, and our South Texas midstream assets, which helped to offset weaker results from other gas midstream properties. Year-over-year, our transport volumes were up 6%, and sales volumes also increased by 6%, particularly in our intrastate business. Gathering volumes rose by 12%, thanks in part to the Hiland acquisition. Power burn increased on our SNG system due to coal-to-gas switching, and we secured an additional 600 million a day in transport commitments with an average term of 13.5 years, with one-third of this capacity being from previously unsold capacity. Since December 2013, we have total commitments amounting to 7.3 DCF, averaging almost 17 years in term length. This indicates strong demand for both existing and expansion capacity in our gas assets. On the expansion side, we’re beginning to notice more of a field-to-market demand rather than a producer-driven push. In the CO2 segment, earnings before DD&A were $281 million, down 23% or $85 million year-over-year, largely affected by lower commodity prices. While our existing EOR developments remain economically viable, commodity prices are impacting this segment. Our production volumes increased, with SACROC up 13% and overall volumes growing by 9%. Although some areas are underperforming, we are achieving cost savings in this environment and anticipate savings exceeding 20% on OpEx and maintenance CapEx. As noted, we also trimmed significant capital expenditures in this segment, as previously discussed. For our Products Pipelines segment, earnings before DD&A increased to $245 million, a 20% year-over-year rise, driven by increased volumes on our KMCC system in Texas and improved throughput on our refined products system in the west SFPP, offset partially by unfavorable inventory pricing in our transmix business. We are seeing advantages from lower commodity prices, with refined products volumes growing by 5.6% year-over-year. We are making progress on the Palmetto refined products pipeline, the Utopia NGL pipeline, and our second splitter in the Houston Ship Channel, all of which are under contract and part of the backlog. In the Terminals segment, earnings before DD&A reached $264 million, up 16% from last year, largely due to organic growth. Our Gulf Coast liquids facilities are performing well, benefiting from expansions in Edmonton and the Houston Ship Channel. On the bulk side, steel and coal volumes are down, but contract minimums protect us from significant impacts. The liquids segment is driving growth as we establish strong positions in Edmonton and Houston, with expansion projects aimed at increasing our storage capacity significantly in these areas. Finally, regarding Kinder Morgan Canada, we are progressing with the $5.4 billion expansion of Trans Mountain. We have passed the halfway mark in the NEB process, anticipating draft conditions this summer and a final recommendation in January 2016. We've made notable headway with communities and First Nations along the pipeline route, securing benefit agreements covering 87% of the path and engaging with around a third of the most affected First Nations. While opposition exists in certain areas, we are exploring a tunneling alternative to mitigate the project's community impact. Overall, we are making good progress that might not be fully recognized in the media. This project is backed by long-term contracts that have been authorized by the NEB.

Thanks, Steve. Let me start first with the GAAP income statement and one comment on it before I move to distributable cash flow. On the GAAP income statement, revenues are down about 11% or $450 million. However, OpEx is down by $531 million or 25%. The largest contributor to this move in revenue and OpEx is our Texas intrastate business where we buy and sell natural gas, largely matching up our purchases and sales. For example, if we enter into a contract to buy at the Houston Ship Channel minus, we also enter into a contract to sell at the Houston Ship Channel flat; with the result being a fixed margin of 10%. Your revenues and expenses are to fluctuate with commodity prices. Changes in revenues are not good predictors of our performance, and we keep focusing on distributable cash flow per share as the best predictor of performance. On the second page of our numbers in the press release, KMI's calculation of distributable cash flow reconciles to GAAP net income. We use distributable cash flow as the measure of available cash for dividends. DCF is calculated as net income excluding certain items plus DD&A, plus book taxes, minus cash taxes, minus sustaining CapEx, plus or minus some other small items. For periods presented prior to the fourth quarter consolidation, we subtract distributions declared by KMP and EPB. For Q1 2015, there are no longer distributions to KMP and EPB, and so all of the DCF is available to pay dividends on KMI shares. The quarter showed distributable cash flow per share at $0.58 versus the declared distribution today of $0.48, giving us over $200 million in coverage. The total DCF number is $1.242 billion, up $669 million or 117%. But much of this is coming from the absence of distributions down from the MLPs. Segment earnings before DD&A in the quarter totaled $1.912 billion, which is roughly flat with where we were a year ago. We expect total segment earnings before DD&A for the full year to be within about 1% of our budget, despite the significant decline in commodity prices. G&A expense for the quarter was $169 million, a $6 million increase from last year. We expect to be about 4% above budget due to the Hiland transaction. Without Hiland, we would be pretty close to budget on G&A. Interest for the quarter was $514 million, up $69 million versus Q1 2014 due to higher balances. The average rate is down slightly. For the full year, we expect to be about 1% above budget due to Hiland. If not for Hiland, we would have less interest expense. Cash taxes for the quarter were positive by $2 million due to state tax refunds. For the full year, we expect a positive position of about $10 million. Sustaining CapEx for the quarter was $104 million, running less than budgeted but that's just timing. For the full year, we expect to be above budget due to Hiland acquisitions and higher relocation expenses. Our budget for coverage for the full year was $654 million, predicated on a $70 per barrel oil price and $3.80 gas. At $50 a barrel and $3 gas, we expect coverage to be around $430 million, which reflects a $224 million decrease due to commodity exposure. In addition to the decrease in commodity prices, we expect a negative impact of about $50 million in our midstream gas segment from lower volumes. Even after these negatives, we expect to be better than the $430 million, due to the Hiland acquisition, interest savings, and CO2 cost savings. In terms of timing of our coverage, it’s not evenly split. The greatest amount of coverage is expected in the first and fourth quarters. We may have negative coverage in Q2, but we anticipate significant excess coverage for the full year.

I just wanted to start off at a high level. There's been a lot of attention about M&A, the recent Royal Dutch deal and so forth. And given your interest in M&A as you've explained at the Analyst Day and so forth, I was wondering if you can give us some color as to what you're seeing out there? Are there distressed assets available or non-strategic assets coming up for sale? Have bid asks narrowed a little bit? Can we expect Kinder Morgan to be active in the coming months, or as things moved with the price of oil and so forth?

I think you can expect us to be active in the coming months. Answering the last part of your question first. Obviously, we've made two acquisitions already: the $3.1 billion Hiland acquisition and the Vopak Terminal acquisition which was just over $160 million. So we've not been sitting on the sidelines. That said, we continue to look for opportunities. But obviously, they have to be a fit in terms of accretion to our shareholders, distributable cash flow, and doability. There is a lot of cheap money out there chasing deals right now, and that is common knowledge considering how much money has been injected into the energy patch recently. I’d like to get Dax Sanders, our Corporate Development Vice President, to elaborate on this a little.

As you said, we’ve spent a lot of time looking at various potential opportunities. But with acquisitions, we have three requirements: we must want the assets, conduct valuation work, and pass social issues. While there are certainly opportunities out there, the bid-offer spreads continue to persist. That said, we have an appetite for acquisitions and a good track record of executing and integrating them. We are spending much time on this.

I have a couple of quick follow-ups. We’ve spent a lot of time in the energy world talking about the price of oil over the last couple of months. But natural gas prices have also declined significantly. When I look at the changes you've announced for your backlog, the only negative change has been in the CO2 business. You’ve been successful in adding projects as well. I was wondering if you could comment on how the natural gas price may impact your backlog or shadow backlog moving forward. Could we see potential negative revisions, or are you insulated from it?

I'll start, and then I'll ask either Steve or Tom Martin to comment on that. The overriding principle is that we are seeing a significant increase in natural gas usage. Long term, we expect it to go from about 74-75 BCF a day today to 110 BCF in the next 10 years driven by demand pull and supply push, providing a tremendous opportunity for a midstream player like us. We see indications of this growth, as Steve mentioned in our capacity sign-ups just in this quarter. The main point is demand will continue driving growth, and we are certainly seeing opportunities.

The demand side is where it's happening. The big example would be Northeast Direct if we can finalize that. There is a supply-demand balance that results from a combination of demand pull and supply push. We expect to see demand pull from LDCs and power plants if Northeast Direct gets under contract, that constitutes the biggest chunk. The addition of power plant expansions this last quarter is also indicative of growing demand. The other aspect is storage; we've signed up about 3 BCF in storage for LNG customers and expect them to need to sign up for more.

Regarding the shadow backlog, we talked about something in the $17.5 billion range within the gas group alone at the analyst conference, and I think that number remains accurate. A significant part of it hinges on Northeast Direct, which is close to moving forward.

Great. One last question for Kim: You mentioned the reconciliation on the equity that was issued under the ATM, along with the goal to reach around 5.6 times leverage by year-end. Can we expect a consistent pace of equity issuance throughout the year? Or does the earnings seasonality, particularly given the second quarter’s often weaker performance, alter your issuance strategy?

The seasonality does not impact when we decide to issue equity. The price may have an impact on timing, but seasonality is not a factor in this decision.

I wanted to ask about the Hiland transaction. Now that you've been working with it for a couple of months and Double H is online, what are you seeing in terms of activity in the area? What are your expectations for volumes? And could you provide an update on the deal?

We closed the deal on February 13th, and the integration is nearly complete and progressing well, considering the tight timeline between signing and closing. In terms of performance since closing and what we anticipate through the remainder of 2015, it's performing in line with expectations, if not slightly better. We did experience some startup issues with Double H, which delayed the ramp-up by several weeks, but it's now running nicely. Initially, we had firm contracts for about 63,000 barrels a day. Following the open season, we now have contracts for 80,000 barrels a day of the 84,000 capacity.

Could you provide the actual volumes now? And what would you expect them to trend towards as you finalize connections to handle short-haul volumes?

We expect to have capacity to move the 84,000 barrels a day and believe the volumes will closely align with that.

On NED, is there a structure or some regulatory work needed for cost-sharing between the LDCs and the merchant generators in that market? Could this serve as a model for other markets?

Yes, there is a regulatory process underway in New England to ensure all power customers can equally share the cost of transportation. This will likely result in utilities temporarily carrying some of the costs, transitioning to power customers later. The format may differ from other regions, but it drives a similar outcome where all power customers share costs equally.

We take a long-term view with acquisitions. There are still opportunities, and we believe in being opportunistic. The hesitation currently is due to the abundance of cheap capital flowing into the energy segment which is preventing companies from selling midstream assets that we would find attractive.

Could you clarify your thoughts regarding UMTP and the revised offering structure with batch movements relative to contract durations? What would it take to get this in the backlog while considering volume and margin trends?

It depends on how market commitments shape up. We're getting interest with the revised model, offering batch purity products through the pipeline, as opposed to strictly y-grade commitments.

Have you considered splitting the NED project to advance the supply side independently from the demand side, or does it require integration?

It is not an integrated project presently. We are exploring each side separately. If we get enough commitment on the supply product, we can move ahead with that. While timelines for both are similar, we could gain clarity sooner on the supply aspect.

Could you update us on CapEx spending for the first quarter compared to budget? Are you still affirming the 10% dividend growth target through the decade?

We affirm our target of $2 this year, with a 10% growth compound through 2020, totaling $3.22 in 2020. We anticipate maintaining substantial excess coverage, with no current indications that would change our outlook.

From a cash perspective for Q1, we spent about $800 million. The accrual figure is closer to $700 million. For the full year, our budget was $4.4 billion, excluding Hiland acquisitions; the total with Hiland included would bring it to about $7.3 billion. We have adjusted spending back and forth based on CO2 segments and added CapEx due to Hiland.

Regarding M&A conversations you've had recently, how important is it for potential sellers to receive cash versus stock?

We haven't observed any strong preference in recent conversations. Circumstances vary, so it often depends on liquidity needs or tax basis considerations, which can influence preferences.

Given your credit metrics, it might be difficult to raise cash through debt. How do you plan to fund any transaction if sellers prefer cash?

If we identify an accretive transaction, the method of funding will not impede completion.

The increased interest in batching UMTP likely arises from producers’ existing commitments to fractionation, making them less willing to commit to additional infrastructure. The flexibility on our end provides them with numerous options as they navigate future uncertainties.

The optionality allows producers to maximize the value from their products, making it an attractive proposition for them and consequently, for us.

Regarding your CO2 transportation projects, what economic conditions need to change for those to become feasible again?

This is a function of CO2 demand, linked to grading quantities and existing floods. Essentially, the main question is what will be deemed economic for CO2 flooding in the enhanced oil recovery context. People are hesitant to make up-front commitments for new floods at present commodity prices, which drive our need for new market commitments.

We’re monitoring economic conditions closely; new floods may require prices to reach around $80 to $85 WTI to become viable again.

Regarding NED, is the main process live, or is it outside the broader New England regulatory process?

The main process is still ongoing, though it is independent of the wider regulatory developments occurring in New England. We can anticipate a decision for its closure either late summer or early fall.

While we aim for major agreements, our priority remains the consultation and accommodation, ensuring we fulfill all legal obligations even without agreements from all parties.

Our game plan, despite the significant drop in commodity prices, is still on track. We're committed to growing the dividend by 10% per year off of this base, with substantial excess coverage.

Congratulations on a much simpler reporting structure. This change could be a bit confusing when considering backlog inventory, especially when factoring in acquisition-related CapEx. Can you provide some clarity on the incremental undisclosed growth CapEx needed to support that 10% CAGR?

We included the high probability share of the Hiland backlog and included it in the project backlog because that represents future capital we’ll incur. We anticipate a combination of acquisitions and additional capital is needed to meet that 10% growth expectation.

The numbers indicate that notwithstanding the significant decline in commodity prices, we expect to be able to achieve that 10% growth. The underlying foundation of our business positions us well, and we believe we can generate those opportunities moving forward.

If we do finalize the conversion project, it may reduce some of the required downstream fractionation capacity based on the mix of y-grade versus purity products in demand.

Production in the Katz and Goldsmith projects is correlating with plans for improvement. Although 2015 will fall short of expectations, we anticipate production increases once the necessary adjustments are made over the next six to eight months.

The oil is still there; it’s a question of extraction. Despite being under plan presently, we project meaningful ramps in production over the remainder of the year.

I'd like to confirm when we can expect updates on the CapEx for the first quarter relative to the budget.

Capital expenditures for the first quarter were about $800 million. The overall budget aims for $4.4 billion, and we’re on track with that even after adjustments for acquisitions.

Given your credit metrics, how might funding play a role with acquisitions if potential sellers show preference for cash?

We can execute transactions that we find valuable without being hindered by funding preferences.

We feel solid about our strategy. The current environment doesn’t deter us. As we maintain our strategy, we are seeing robust opportunities while remaining agile.