National Fuel Gas Company. Second Quarter Fiscal 2018 Update. May 4, 2018

Transcription

1 National Fuel Gas Company Second Quarter Fiscal 2018 Update May 4, 2018

2 C O R P O R A T E P A R T I C I P A N T S Brian Welsch, Director, Investor Relations Ronald Tanski, President and Chief Executive Officer John McGinnis, President of Seneca Resources David Bauer, Treasurer and Principal Financial Officer C O N F E R E N C E C A L L P A R T I C I P A N T S Holly Stewart, Scotia Howard Weil Christopher Sighinolfi, Jefferies & Company P R E S E N T A T I O N Operator: Good morning. My name is Mike and I will be your conference operator today. At this time, I would like to welcome everyone to the Q National Fuel Gas Company Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers remarks there ll be a questionand-answer session. If you would like to ask a question during this time, press star, then the number one on your telephone keypad. If you would like to withdraw your question, press the pound key. Thank you. I will now turn the call over to Brian Welsch, Director of Investor Relations. You may begin your conference. Brian Welsch: Thank you, Mike, and good morning. We appreciate you joining us on today s conference call for a discussion of last evening s earnings release. With us on the call from National Fuel Gas Company are Ron Tanski, President and Chief Executive Officer, Dave Bauer, Treasurer and Principal Financial Officer, and John McGinnis, President of Seneca Resources Corporation. At the end of the prepared remarks we will open the discussion to questions. The Second Quarter Fiscal 2018 earnings release and May Investor Presentation have been posted on our Investor Relations website. We may refer to these materials during today s call. We would like to remind you that today s teleconference will contain forward-looking statements. While National Fuel s expectations, beliefs, and projections are made in good faith and are believed to have a reasonable basis, actual results may differ materially. These statements speak only as of the date on which they are made, and you may refer to last evening s earnings release for a listing of certain specific risk factors. 1

3 National Fuel will be participating in the AGA Financial Forum Conference later this month in Phoenix. If you plan on attending, please contact me to schedule a meeting with the Management Team. With that, I ll turn it over to Ron Tanski. Ronald Tanski: Thanks, Brian, and good morning everyone. National Fuel s second fiscal quarter was another good one and some recent developments that we highlighted in last evening s earnings release set us up for continued good news down the road. Dave Bauer and John McGinnis will cover the operating segment details for the quarter in just a little bit. As you know, National Fuel s strategy to increase the overall value of our integrated company has been focused on the development of our natural gas properties in Appalachia and the buildout of our interstate natural gas pipeline system. We remain committed to the utility business and plan to invest $90 million to $100 million each year in this segment to maintain a safe system for our customers, given the stable population in our utility service territories and our high market saturation, our utility business earnings are trending to be only 20% of our consolidated earnings. In our midstream pipeline and upstream production segments, however, we have the opportunity to grow each business and achieve higher returns that are available in the regulated utility business. When our Northern Access Interstate Pipeline Project ran into a roadblock last year, we began talking about the possibility of an additional project that we might build to transport Seneca s natural gas production from our Western Development Area to a more liquid market area with stronger natural gas prices. Earlier this week, Seneca signed a Precedent Agreement with Transcontinental Gas Pipeline to develop a project that would do just that. We re in the early stages of development for this project, but generally, it would allow Seneca to transport 300,000 dekatherms per day of production from its Clermont-Rich Valley area to Transco Zone 6 markets. Transco is currently having discussions with other potential shippers to see if the project can be upsized above this 300,000 a day on portions of its system and into Zone 6. This project will also involve a meaningful capital investment by our Supply Corporation. Since Transco currently has no facilities in the Clermont-Rich Valley area, Transco and Supply Corporation are in discussions for Supply to modify its FM100 modernization project that is currently in a prefiling phase at FERC, and build the first leg of the transportation path to accommodate Seneca s 300,000 a day from Clermont-Rich Valley to Leidy. We expect that Supply will enter into a long-term agreement to lease this capacity to Transco. Using this leased capacity, Transco could then provide Seneca a complete path from Clermont-Rich Valley to Zone 6 markets at a single rate. We expect the transportation rate on this project will be extremely competitive to the Northern Access rate. While this 300,000 dekatherm per day project is smaller than the 490,000 a day Northern Access Project, it does three important things for us. It creates an alternate outlet for Seneca s production. It allows Supply Corporation to expand its interstate pipeline system and boost its earnings over the long term, and it furthers our ongoing system modernization of older system pipelines. Now, as I said, we re at the early stage of this project s development and all parties are targeting an inservice date of late We ll expect to give more updates on the project in future calls when we hit various milestones. Meanwhile, our Northern Access Project is still held up in litigation at the Second Circuit and awaiting a FERC order on re-hearing. As we look at the possible construction logistics for our Northern Access Project, given the various tree-cutting restrictions, environmental construction conditions and the long lead times for various materials and equipment, we currently believe that even if we received a positive 2

4 resolution from either the Second Circuit or FERC soon, we would likely be looking at an in-service date for Northern Access in the fall of An obvious question then arises- would we do both projects? From a pipeline perspective, we believe that in the current market both pipeline routes offer good value to shippers and access to different markets. In addition, the $0.5 billion Northern Access Project and the $250 million to $300 million Supply modernization and expansion project would not unduly stretch our projected credit metrics. The bigger question is, would Seneca be able to fill both pipes: 490,000 a day on Northern Access and 300,000 a day on the Transco/Supply Project. While we have the acreage and well inventory to do that, but a substantial increase in our capital spending would have us looking at additional financing options to fund the extra drilling that would be required to fill up that much capacity. We would view that as a good problem to have and one that we ve solved before. However, we have plenty of lead time before gas would start flowing into either of those projects so we ll be keeping an eye on commodity price outlooks, basis differentials, capital costs and the overall state of natural gas markets as we move forward. Keeping on the topic of pipeline projects, I ll note that we filed our FERC application for our Empire North Project in February. This 205,000 dekatherm per day increase in throughput on our Empire Pipeline is fully subscribed and involves adding compression on the existing pipeline. Based on the proximity of our proposed New York compressor station to high voltage power lines, and in order to minimize emissions and simplify the permitting process, we designed this compressor station to utilize an electric drive compressor. These types of compressors and the required interconnection with the electric grid have a long lead time and we project that we should have this new service available in the summer or fall of Switching to our upstream exploration and production operations, we noted in last evening s release that Seneca will be contracting for a third drilling rig this quarter in its Appalachian operations. There s a number of reasons for adding this one rig now. From a marketing perspective, we re having continued success at locking in firm sales for Seneca s production for meaningful periods of time at economic prices, and we re not substantially relying on the spot sales market. Over the longer term, as I mentioned earlier, we re working toward two possible exit solutions for the WDA production. From an overall return on capital perspective, our Utica drilling program in the WDA can utilize the well pads that we previously constructed for our Marcellus wells, and production will flow into existing gathering and compression infrastructure. By increasing our production throughput in our existing gathering system, we improve the economics and efficiencies of our overall program, which are already very good. The combination of our stacked Marcellus and Utica production zones, and the integration of our production, gathering, and transmission operations provide for a very efficient use of our capital. From an operational perspective, Seneca is at the point where it is basically completing all its drilled wells on a just-in-time basis. In other words, we don t have an inventory of drilled but uncompleted wells or DUCs. As we move into the drilling of more Utica wells that have a longer drilling time, having more DUCs available gives us a lot more operational flexibility in our pressure pumping operations. Adding the third rig will help us improve the efficiency of our single completions crew. As with all three of our drilling contracts, we re committing to this rig for a one-year term. Our next renewal options for one of our other rigs comes up this December so we have plenty of operational flexibility if we need to adjust our drilling plans. As always, we re being careful with our consolidated capital spending. We lived within cash flows over the past two fiscal years, and we re looking for our production and gathering operations to generally live within cash flows in the future. However, we believe there is good rationale to slightly outspend this year to improve the overall economics of our production and gathering operations. Now I ll turn the call over to John McGinnis to give some more details on our Exploration and Production segment. 3

5 Thanks, Ron, and good morning everyone. Seneca produced 46.1 Bcfe during the second quarter compared to 45.6 Bcfe in last year s second quarter. In Pennsylvania, we produced 41.4 Bcf, a slight increase over last year s second quarter. Quarter-over-quarter our production was up by almost 17%, largely driven by bringing on new pads in both the Eastern and Western development areas, no curtailment during the quarter, and the addition of new compression in Tioga. From a long term strategic perspective, we are pleased that Seneca has been able to enter into a precedent agreement with Transco for 300 million a day of new firm transportation capacity that Ron just discussed. This new firm transportation capacity provides a path from the WDA Clermont-Rich Valley Gathering System to premium markets connected to Zone 6 of Transco s interstate pipeline system. One of the unique attributes and key benefits to Seneca is the transportation path allows flexibility in how we fully utilize the capacity. We can flow our production from both the CRV Gathering System and our Lycoming County acreage into this new firm capacity, our two largest and most economic development areas. Seneca will be an anchor shipper on this new project. As Ron discussed earlier, this project does not alter our interest in Northern Access. Our WDA acreage has more than enough Marcellus and Utica drill inventory to fill both of these pipeline projects. Regarding current operations, we now have nine Utica wells producing in the WDA, eight in the CRV area, plus our most recent appraisal well located in an area we call Boone Mountain, approximately 30 miles south of CRV. This well is on trend with our best WDA Utica well located in Rich Valley, and has now been online for over 30 days. On a normalized basis, the IP7 and IP30 rates were essentially identical to this well, and early production history suggests that it will also have an EUR per thousand foot of-well over 2 Bcf. In addition, the Utica Point Pleasant Zone at Boone Mountain has two distinct reservoirs that we have not seen previously. Our first well targeted a shallower, lower Utica zone, similar to our target in the CRV area, but when we return to Boone Mountain, we will test a deeper Point Pleasant section to determine which zone delivers the highest productivity. We have additional appraisal drilling to conduct between Rich Valley and Boone Mountain, but if results remain consistent, this will open up a new Utica development corridor. We continue our transition to a full development Utica program in the WDA. Based on results to date, our Utica program should deliver wells that range from 1.5 to over 2 times larger than our WDA Marcellus wells on an EUR per foot basis, but only cost between 40% to 45% more. These wells take longer to drill since they are quite a bit deeper, and on average will have longer laterals. Over the next 18 months, approximately 60% of our WDA cap ex will be directed towards Utica development. On the marketing front, we continue to see opportunities to add to our portfolio of firm sales. While the Atlantic Sunrise Project is expected to go in service later this summer, providing us with 190 million a day of firm transportation where we have already locked in sales at premiums to NYMEX, it will be a few years before the new Transco/NFG Supply Project is able to provide additional firm transport for our WDA production. As such, we recently executed almost 50 Bcf of new firm sales to lock-in basis or fixed pricing for our WDA and EDA production. Of that amount, approximately 17 Bcf is locked in at a realized fixed price of $2.27 and heavily weighted to securing Fiscal 19 cash flows. The balance of the firm sales, over 30 Bcf at a fixed basis of NYMEX minus 59 provide additional takeaway capacity for our WDA production volume. A portion of the 30 Bcf of new firm sales begin in Fiscal 2020 and provide a nice addition to our portfolio, helping bridge the gap to the in-service date of our new projects. Returning to Atlantic Sunrise, we have recently adjusted our production guidance to reflect an estimated in-service date of August 1st. This is still a moving target but at this point any additional delays are likely weeks as opposed to months. Further, to take full advantage of the firm sales associated with this capacity, we have adjusted our operations schedule, pushing back the online date of two Gamble pads in 4

6 Lycoming County with a total of eight wells to now target flow back within the first couple of weeks of August, about a month later than assumed in the last update provided. This change has a modest impact on our Fiscal 18 production guidance, reducing our forecasted production by a few Bcf, but we prefer the short wait in order to sell our production into an improved market once Atlantic Sunrise is in service. We will continue an active dialogue with Transco on timing and lock in our operations schedule once we gain more clarity around the exact in-service date. Looking at the remainder of Fiscal 2018, we re in great shape on a marketing and hedging front. We have approximately 60 Bcf locked in at an average realized price of $2.45 per Mcf and another 18 Bcf of firm sales with basis protection. Spot sales for the remainder of the year are very modest at less than 12 Bcf. Over the next few quarters, as opportunities arise, we will continue to chip away at our Fiscal 18 and 19 spot sales exposure. Finally, with our success in locking in firm sales over the next couple of years, and as we look to grow into our future firm capacity, we have decided to add a third rig this quarter to accelerate our WDA Utica development program. The additional rig will be primarily dedicated to the redevelopment of Seneca s CRV acreage, an area with up to 125 well locations on existing pads already tied into existing upstream and gathering infrastructure. The third rig will also improve our operational flexibility and enable us to continue to drive down our drilling and completion costs on a per well basis. Going forward, we ll have one rig in the EDA to develop Lycoming Marcellus and Tioga Utica, and two rigs in the WDA, primarily focused on the Utica program. Moving to California, as of May 1st we sold our Sespe Oil Field in Ventura County for $43 million. The divestment of Sespe was primarily a strategic decision driven by its remote location from our current county operations, increasing regulatory restrictions and the absence of significant growth opportunities. Our operations will now focus exclusively in the San Joaquin Basin, and Kern and Fresno counties. I would like to personally thank our Sespe field operators who have done a fantastic job operating this field over the past 30 years. Our acquisition of the Sespe Oil Field was Seneca s entry into California 30 years ago. We produced 662,000 barrels of oil during the second quarter, a slight decrease quarter-over-quarter. Though we were down slightly, excluding Sespe, we are now beginning to reverse this decline. Daily production in March averaged 400 barrels per day higher than in February, with production growth at most of our fields. As a result of adding the third rig, we are now raising our capital expenditure guidance by $40 million from the midpoint of $320 million to a midpoint of $360 million for Fiscal 18. Since we re adding this rig late in the fiscal year, we will not see related production volumes until next year, and over the next few years, however, we now expect to grow our natural gas production on average between 15% to 20% a year. With that, I turn it over to Dave. David Bauer: Thank you, John. Good morning everyone. National Fuel s GAAP earnings for the second quarter were $1.06 per share. Excluding an entry we made to adjust our deferred tax balances, our adjusted operating results were $1.11, up $0.07 over last year. At our Utility, colder weather and the impact of new rates in our New York division drove the nearly 30% increase in earnings compared to last year. As you ll recall, last April we received an order in our New York rate case that increased rates by $6 million, the bulk of which was realized in the second quarter when throughput is seasonally the highest. In our non-regulated operations, the more than $5 per barrel increase in crude oil realizations was a great tailwind, but unfortunately it was more than offset by a $0.44 per Mcf decrease in Seneca s natural gas price realizations. This was generally expected given the rolling off of some favorable hedges that were in place through last year. 5

7 Pricing in Appalachia has remained supportive throughout the winter and we haven t experienced any price related curtailments since last November. We continue to work our way through federal income tax reform. During the quarter, further guidance and clarification was issued by the IRS, particularly around the alternative minimum tax, which led us to revise the first quarter entry we recorded to reflect the impact of tax reform on the deferred income tax balances on our balance sheet. Since that adjustment is a refinement of the previous accounting entry, we reflected it as an item impacting comparability in last night s release. The effective tax rate on our income statement is expected to be in the 26% to 27% area for this fiscal year, and about 25% in 2019 and beyond, once we move to the 21% statutory rate. With respect to cash taxes, the new tax law should have a very favorable impact on the company. Over the past several years, we ve accumulated approximately $100 million of tax credits, principally alternative minimum tax, enhanced oil recovery, and research and development credits. Under the new tax law, the AMT credits are refundable. As a result, for Fiscal 19 through 2020, we expect to be in a net tax refund position. Longer term, once we ve worked through our NOLs and tax credits, we expect our cash tax rate will be in the 15% area, and that includes both federal and state tax payments. FERC and our state regulators have been active addressing tax reform. In late March, FERC instituted a number of different tax-related proceedings, including a Notice of Proposed Rulemaking that would mandate a review of natural gas pipeline cost of service rates in light of the reduction in the corporate income tax rate. This proceeding will play out over a number of quarters, and given the timing of when our pipelines would be required to file the new Form 501-G, it should not have any impact on our Fiscal 2018 results. From a practical standpoint, we think it s likely this tax proceeding will be rolled in the routine rate proceedings that we expect at both companies over the course of the next 18 months or so. Also in March, FERC issued a new policy statement that eliminates MLPs ability to recover income taxes. As a reminder, NFG s FERC regulated pipeline subsidiaries are structured as C-corps so this new policy will not impact us. Both the New York and Pennsylvania utility commissions have now initiated proceedings to look at the impact of tax reform on rates charged to customers. In both proceedings, it s clear that the states intend to preserve the net benefits of tax reform for ratepayers. The proceedings will be completed over the course of the next several months, and in the meantime we ll continue to defer the impact of tax reform in both jurisdictions. For the full fiscal year, we expect to record a refund provision of approximately $16 million. Turning to guidance, we are tightening our earnings guidance to a range of $3.20 to $3.35 per share. As a reminder, this excludes the remeasurement of deferred income taxes that I mentioned earlier. The two primary drivers that led us to decrease the high end of the range includes the earnings impact of the sale of our Sespe oil properties and the reduction in our Henry Hub gas price assumption from $3 to $2.75 per MMBtu. These are somewhat offset by our strong results for the quarter, an increase in our NYMEX oil price assumption from $60 to $65 per barrel, and the expectation of continued cost control across the system. We have limited spot volumes forecasted and are well hedged for the remainder of the year with more than 80% of our oil production and almost 70% of natural gas production hedged at attractive prices, so any volatility in commodity prices will have a limited impact on our results. 6

8 The remainder of our other key earnings assumptions are generally in line with previous expectations and are summarized in last night s earnings release. Looking at capital spending, we re increasing our Fiscal 18 guidance to a range of $610 million to $680 million. As John mentioned, this increase is primarily attributable to the addition of a third rig at Seneca in May. The other businesses are largely in line with our previous forecast. The third rig will add $40 million in capital this year which will be largely funded with the proceeds from the Sespe sale. As a result, for the year we continue to expect our capital spending will be in line with our cash from operations. Looking forward, we expect the new rig will increase Seneca s capital spending by about $100 million to $150 million per year, depending on the pace of completions. Seneca s increased activity will have an outsized impact on the cash flows of our gathering business. As John mentioned earlier, the third rig will be mostly drilling Utica wells from our Marcellus pad locations in the Clermont-Rich Valley area. Production from these Utica wells will flow into our existing gathering infrastructure. Consequently, over the next few years, capital spending on gathering and compression in the WDA should be very modest. As Seneca s production grows, the Gathering business should generate substantial free cash flow. On a combined basis, and assuming the current strip, we expect the Gathering and E&P businesses will have a small outspend in 2019, will pretty much live within cash flows in 2020 and then will generate free cash flow in 2021 and beyond. With that, I d like to turn it over to the Operator and open the line for questions. Operator: At this time, I d like to remind everyone in order to ask a question, press star, one on your telephone keypad. We will pause for a moment to compile the Q&A roster. Your first question is from Holly Stewart from Scotia Howard Weil. Holly Stewart: Good morning, gentlemen. Ronald Tanski: Good morning, Holly. Holly Stewart: Maybe, Dave, since you just kind of threw out those cash flow numbers, that was sort of my first question. Kind of you mentioned in the release you d essentially over a multiyear period be sort of self-funding E&P and Midstream with cash flow. So, you kind of gave some specifics. I was just curious if you could maybe provide, I don t know if it s commodities or how you want to look at it but some of the assumptions around that living within cash flow. David Bauer: It would be at the current strip, so say in the $2.75 area long term. Holly Stewart: Long term, okay. Great. Then the rig count still at three? 7

9 David Bauer: Yes. Holly Stewart: Okay, that s great. Maybe just one on the new delineation well, the Boone well. Can you just talk about well design, completion design? Is it similar to what we ve done so far in the WDA in the Utica? Just kind of thinking about what kind of changes we re making there. Actually, Holly, it s very similar. We did that on purpose. It s a short lateral, it s just barely over 4,000 foot, but we did that on purpose because we wanted to compare it apples-to-apples to what we were doing in the CRV area. It s a little bit deeper, a little bit higher pressure, but at the end of the day both the drilling and completion design was very similar. It was still the same target of what we see in CRV. Holly Stewart: Okay, that s great. Makes sense. Then just one more, I guess, on the delineation. How many wells do you think you need to do to sort of prove that out from a delineation perspective in the WDA? Thirty miles is a long distance, so we are certainly, I would say two to three additional appraisal wells, anywhere between Rich Valley and Boone Mountain would give us a pretty good you know, if we see consistent results, we re going to be pretty comfortable that the entire corridor will work. Honestly, in my opinion, I think it s fairly low risk. I think it will work, but again, until we drill and test those wells, you never know. Holly Stewart: Okay. Thank you guys. Operator: As a reminder, to ask a question, press star, one on your telephone keypad. The next question is from Chris Sighinolfi with Jefferies. Hey, good morning, guys. Ronald Tanski: Good morning, Chris. You announced a lot last night, Ron, so I have more than just one and one follow-up, if that s all right. I want to start, John, if you can just talk in broad strokes. There were a number of strategy changes it seems announced last night, the sale of Sespe and the refocus on Midway Sunset, the addition of the third rig in Pennsylvania and the Utica development in the WDA, and then just the general acceleration of 8

10 Seneca gas production. You know, a lot of clients are, a lot of investors worry about residue gas and the role that it will play in supply and demand dynamics going forward, and importantly on pricing. In response to that, some of your Northeast producer peers have talked about scaling back gas production. So, I m just wondering, in contrast to sort of that sentiment we re getting from some of your peers, just some of the Seneca plans, your comfort with them and then maybe how it s a little bit different for you. Sure. Let s begin with California. We ve been looking to sell Sespe for quite a while, to be honest. It s remote to our operations quite a distance. We actually closed on this agreement probably I d say late summer, very early fall last year, actually it was sort of late summer. Then there was, as always seems to be with Sespe, some permitting issues so it extended it for a period of time before we could really close it, but we had been looking to sell it for quite a while. It s a great asset but it has a declining production base, it s very expensive both on an LOE basis and in terms of drilling new wells. We d been trying to get well permits there for years and it s just been very difficult, since it sits within a national forest and a condor sanctuary in Ventura County. We felt that rather than wait and watch it continue to decline over the next few years that we would move forward and sell it when it s continued to have some pretty good value attached to it. Moving over to the East, as you know, we ve been looking for new exit capacity for quite a while. We were down to one rig for a period of time, ramped up to two rigs lately when gas prices improved, and in moving towards Atlantic Sunrise to be able to make sure that we had volumes ready for that, and so when we entered into this precedent agreement with another additional 300,000 within three years, it gave us a pretty good guide in terms of how many rigs we would need to fill that very comfortably, and that s three rigs. Our marketing group has done a superb job on locking in Fiscal 19 volumes and we have already begun work locking in volumes in 2020 and beyond, and so from a spot exposure or from price exposure, we ve done quite a good job in terms of at least reducing a lot of that risk. At three rigs, given our well inventory, it just made a lot of sense for us, once we were able to guarantee at this exit capacity, it just made a lot of sense for us to ramp up bit. David Bauer: Chris, this is Dave. I d add to that that because of the investment that we ve already made in Gathering infrastructure, which is covered by the Marcellus wells that we ve drilled, this production is highly economic, right. So you think of our economic tables in our price decks, you could pretty much subtract the $0.50 gathering rate from that and that will give you a sense of the economics that we should be able to achieve, or what a breakeven price would be. Yeah, and I know, Dave, that was a long-term plan of yours. You had built the gathering systems to be able to take the higher pressures from the Utica so I know that this was ultimately planned, and John sort of addressed it. I was just asking why this, why now? It seemed like it was tethered pretty carefully to the evacuation capacity you re adding with Transco and Supply. Absolutely, Chris. 9

11 I guess as a follow-up to that, John, are there other assets within the portfolio like Sespe that are candidates for pruning, or is anything in flight on that front? You talked about the job your team has done, and Ron talked about it in prepared remarks on in-basin firm sale agreements to bridge the gap between your production ramping and the targeted in-service of this Transco and Supply capacity. I m just wondering how you think about it, and how that team thinks about it in the context of Atlantic Sunrise, Rover and Nexus poised to come online. What do you think happens in-basin? Are those buying from sale agreements from you or entering into them with you? How are they thinking about those pipes and the impact they might have on the local markets? It s a long question. Sorry about that. I ll focus on what I heard last. Honestly, I think, in my opinion, once those pipes come online, the basis differential in Pennsylvania should tighten. Not sure what it ll do to NYMEX but I think the basis differential both on the Transco pipes and Tennessee pipes should tighten up. That s one reason we ve actually held off a bit in terms of being even more aggressive because we think there will be a little bit of improvement, especially on Transco. We think there will continue to be opportunities to layer in additional sales once those pipes come on. How that impacts the big picture, Midwest, well, obviously NYMEX and Henry Hub pricing is to be determined. Ronald Tanski: Chris, with your question with pruning assets, pretty much all the time we re looking at what makes sense and what doesn t to have, and there have been minor sales, so minor that we really never even talk about them with respect to our shallow production, our old Devonian sandstone production, and then more recently some of the early appraisal wells that were kind of outliers from the rest of our gathering system that, as I said, they re not meaningful in a big way when it comes to dollars but we re always looking at rationalizing the operations. Just let me continue with that. In terms of California, part of why we were comfortable selling Sespe now is because we have entered into two additional farm-ins in Midway Sunset. One in the south called Pioneer, one in the north called 17N, and once we begin to move on those and bring those into development, we think we ll get some pretty good production growth related to those. We do have our focus will be in Kern County and we believe that s an area that we can certainly keep our production flat to if not slightly growing over the next few years. Okay, great. I guess your market view around basis tightening, Dave, when it comes to how you re forecasting cash flows, if I think back to your answer to Holly, you re not assuming that; you re just running current strip and current basis differentials. David Bauer: Yes, that s right. 10

12 Dave, I guess on the Transco/Supply Project, I m just looking for a little bit more color on maybe what we should expect from a regulatory filing, key approval process milestone, simply because this seems to a be a little bit different that what we ve seen from you or peers in the past where marrying capacity adds to the modernization initiative. So I just don t know if it s supposed to follow if we should expect it to follow the same cadence and the same process or if there s anything unique about it. David Bauer: Actually, Chris, a number of our expansion projects that we ve done on our Line N System have all involved modernization, so you could use those, if you were interested in seeing the details, look at those proceedings, like our West Side Modernization Project is a classic example of that. From our end, we ve already started the FM100 modernization filing process and we ll be adding to that then the expansion component, and then over time we ll, as Ron said, negotiate a lease, and I think you could use the first Northern Access Project that we did excuse me, the Northern Access 2015 Project that we did where Tennessee had leased capacity that we had expanded on our system. I don t know that we re we re not charting any new waters here from a regulatory perspective. Okay, yeah. Thanks for the reminder. I had forgotten about that, the Kinder example is probably the best one. Okay. Then I guess just final question for me, and sorry to take so much time, but Ron, externally it doesn t appear as though much has changed with regard to the Northern Access appeal since the last quarterly call, but there have been some updates with Constitution recognizing, of course, that the two projects are not the same nor are their appeals, but just figured it would be worthwhile to ask for an update from you as to any current thoughts on how your appeal might shape up. Ronald Tanski: Yes. You re right. The only thing we ve seen is the Supreme Court denial of the Constitution appeal. We don t think it really changes our situation much at all. Again, as we said before, if we thought it was an easy answer for FERC they could have simply denied us like they did Constitution back when, and the fact that it s taking so long really does show you the kind of differences and nuances between various projects. So, no, our view hasn t changed on that at all. Okay, great. Guys, thanks a lot for the time this morning. You bet. Operator: There are no further questions at this time. I will turn the call back over to the presenters. Brian Welsch: 11

13 Thank you, Mike. We d like to thank everyone for taking the time to be with us today. A replay of this call will be available at approximately 3:00pm Eastern time on both our website and by telephone, and will run through the close of business on Friday, May 11. To access the replay online, please visit our Investor Relations website at investor.nationalfuelgas.com. To access by telephone, call and enter the conference ID number This concludes our conference call for today. Thank you and good-bye. Operator: This concludes today s conference call. You may now disconnect. 12