An Interview with Manitok Energy CEO Mass Geremia – Part One
Manitok Energy is a conventional operator focused on projects in Alberta, and the company has spent the last several years amassing a considerable land position with output now approaching 6,000 BOEPD. Its footprint now extends 449,000 gross acres (93% working interest), of which 430,000 gross acres (94% working interest) have yet to be developed. In July 2015, the company closed a deal that bolstered its position with a $61.5 million acquisition of more than 67,000 gross acres with volumes of 1,800 BOEPD ($34,167 per flowing BOEPD).
MEI management, led by president and CEO Mass Geremia, has established a goal of reaching 20,000 BOEPD within five years by capitalizing on future acquisitions and organic growth.
Oil & Gas 360® had an opportunity to speak with Mass Geremia about his company’s July acquisition of the Wayne assets and delve deeper into those assets and other operations in Alberta.
Oil & Gas 360®: Thinking back to your 1,800 barrel per day acquisition this year, the $61 million -$62 million purchase of the Wayne assets in Southeast Alberta, what does the asset bring to Manitok?
Manitok Energy: it’s a couple things: one, it adds to our land position in the Entice area, it marries really well with the lands, it has the exact same play types that we’re going after—the Lithic Glauc and the Basal Quartz, so all of it really is chasing the same geology and the same opportunity. However with it we get a twenty five thousand barrel a day oil facility and terminal.
That gives us a lot of control of our operation cost in the area, should allow us to become a low cost producer in the area and therefore a more dominant player in that area and allow us to be best in class in our area. It does make a world of difference in terms of just having land by adding the facilities; now we’ve married the two together, and now we’ve got a base to build upon for future growth with the undeveloped lands and then the drilling locations that we’ve identified.
O&G360: Can you talk a little bit more about that facility and terminal? Is that a rail terminal, or what is that?
No, it’s basically an oil treating facility; it handles twenty five thousand barrels a day of fluid so you truck your effluent into it. Some of the field is piped—pipeline tied—so that we can pipeline our effluent straight into the facility which then saves the [cost of] transportation and treating at the wellhead.
So it has 25,000 barrels a day of fluid handling capacity. We’re pipeline-tied to an oil terminal and we can deliver close to 7,000 barrels a day of oil directly to that pipeline and that is expandable with just adding more compression and so on, we could push more oil down that line. Also have 26,000 barrels a day of water disposal. Some of the lower Mannville plays to the east of us have 25% to 35% water cut, so it’s much easier to dispose of the water—treat it in the facility, separate it and then dispose of it.
Also there’s a gas plant attached to the back of it so it’s about a ten million a day gas plant as it currently sits. And it’s also built for sour spec because it was initially built to handle a Nisku pool which had sour oil in it so we could take the gas associated with any of our oil and run it through there, and with say a million, half a million dollars of compression expansion we can get twenty to twenty five million a day of throughput in terms of gas.
And then we have four million a day of acid gas disposal as well. It’s tough to replicate that facility. It would be very difficult get a license for it. If you could get a license for it, it would probably be $20 million to $25 million to rebuild. It’s the largest facility within fifty or sixty miles in that area, so it is significant.
O&G360: It sounds like that plant is as significant as the prospective property.
MANITOK: Absolutely. It allows us to take third party volumes in. Effectively, if anybody else comes in to try to do deals with Prairie Sky on the lands that we haven’t tied up to date, it does make it more difficult [because] anything they produce will come through our facility; so, one, we get some good intel on what’s being drilled and how much fluid it’s producing; and secondly, it is more challenging for groups to come in without having to deal with us first.
O&G360: What are the next steps on the E&P side to develop the property?
MANITOK: What we’re doing now is we have the large facility in the north end and we’ve got the discovery at Carseland in the south end, so basically we will develop both ends over the course of 2016-2017. Again we can continue to piggy-back off our success and Carseland where we had two 300-barrel a day oil wells in the Lithic Glauc, another 20 or so locations so we’ll start to develop that channel. We will drill up near our Wayne facility testing both Lithic Glauc and some Basal Quartz ideas probably over the course of 2016-2017 and focus on developing the pools at both ends, and then likely developing further the pools in between more likely in 2017-18.
We do have over 300 identified horizontal locations in both the Lithic Glauc and Basal Quartz, so basically what we’ll be doing is starting to delineate the reserves, start to drill those wells. Of those 300 wells, approximately eight are booked in our reserves right now, so there’s a lot of that that could move into our reserves as we drill them up.
OIL&GAS360: Can you compare this to any U.S. shale plays for example? What do the laterals look like and what types of completions?
MANITOK: What we’re developing here in the Lower Mannville is more of a tight sand. Vertical wells were drilled back into these zones back in the ‘70s, ‘80s and ‘90s, and it was hit and miss. You’d hit a pool, you’d drill a few more wells, and then you start getting into some tighter rock. It was more gummed up a bit with some of the clays and things like that. So we’re not talking about shale or really, really tight rock; we’re talking about a sort of gummed up decent reservoir—[after] the advent of the multi-stage fracturing and then us going back in there.
We didn’t invent this concept. Cenovus [Energy], another large Canadian company, had drilled about forty horizontal wells into the Basal Quartz zone about ten miles east of our land position—successfully. So we keyed off of that, knowing that it had been done before.
We’re using 15-25 ton fracs, 10 to 15 stages, not the massive 200 tons per stage type frac—it’s smaller scale fracing, really just to open up the reservoir. We found with our Carseland success that the area is very conducive to the multi-stage fracturing and we’re not seeing the same sort of seventy eighty percent declines you see in the tighter shale plays— we’re seeing more halfway between shale and a conventional reservoir: 40% to 50% first year decline.
O&G360: You mentioned the Prairie Sky agreement a few minutes ago; can you talk about the revised land agreement you have and what’s the net effect on Manitok?
MANITOK: When we originally did the deal, it was done with Encana. Subsequent to our deal being done on the land, [Encana] rolled out Prairie Sky as a separate public entity on the Toronto Venture Exchange with a focus on just royalty lands.
It was quite a large land base; we had concepts but no real clear understanding of exactly what we [should] chase 110% for sure—so it was tough to put a royalty scheme to it. So we put a broad based royalty scheme to it and we began to drill and move forward. We began to get some results on the wells and we wanted to go back and alter the royalties to be more conducive to the actual zones that we’ve identified now as our focus.
We were able to reduce our royalty. It’s a sliding scale from ten to thirty percent but it’s basically an Alberta Crown logarithm. When you get anything north of sixty-seventy barrels a day or you get into seventy-eighty dollar per barrel oil range, it goes to thirty percent real quick. So we negotiated a 17 ½% flat rate on our royalty. That allowed us to improve the rate of return and shorten up the payout by twenty five percent or so.
We’ve added more lands in the area that were more along the trends that we’ve discovered now and also extended the deal and spread out the capital commitments over a longer period time. We extended the deal now to April 30, 2018—the primary term, and we have an option to extend for four additional years to 2022 under the same terms. So if we find more oil and more gas, we’re not having to pay up for it to extend it. We already have extension terms.
So all that is very favorable. It shows the willingness of Prairie Sky to work with us.
O&G360: Could you update us on what the opportunities are up in Stolberg? What’s your plan there?
MANITOK: Well right now we’ve drilled over 30 wells into the Cardium oil pool there; we’ve identified still another 15 or so locations that we could drill. We’re evaluating the purchase of 3D seismic in order to better help us with understanding what oil we’ve produced and what we’ve left behind, so we can identify more locations. And then more importantly we’re working on a waterflood. It’s a six mile trend but it’s in an area in the foothills where the geology is folded and faulted, very structured. So it’s separated into multiple pools. The two biggest pools are to the north, extending about two miles long each. The first one is called by the regulatory bodies “The F Pool.”
We’ve got our partners onside, our applications have been approved and so on; so we should be able to move the waterflood there forward in first quarter of 2016; and what that’ll do is it allows us to repressurize the reservoir—to stabilize production and declines. Take our recovery factor from around 10% off primary recovery to more like 20%-25% with the waterflood.
We’re excited about getting the waterflood going. We’ve seen waterflood activity to the east of us in the Cardium—or in the in the plains with a little bit flatter terrain—be quite successful: they have achieved recovery factors of 20% to 30% recovery factors successfully in the Cardium. Because of the folding and faulting, our Stolberg structure is upright as opposed to flat and so that upright orientation is more conducive to probably a higher recovery factor on the flood. So that will be interesting over the next couple years as we implement the floods and get greater recovery.
Also we have developed quietly along with the oil play a gas play. A Mannville gas play. And we’ve now drilled two vertical wells successfully. Both of them have done or are on their way to doing 5-6 Bcf per well.
We drilled a horizontal well last year. It’s been on production now for a year and it’s on track to do something in between 8-10 Bcf . We can see the Mannville trend go through our land base. It’s a liquids-rich Mannville, about fifteen barrels per million of condensate with it, and with the high IP rates and the large reserves per well it’s economic at today’s commodity pricing. Up in Alberta we’re getting $2.60 per gigajoule. At these current strip prices our rate of return on these wells is f40%-60%, depending on the assumption on the reserves.
So we’ll be moving that play along slowly, probably not in 2015, but more so in 2016. So there’s still more legs to Stolberg. We have some land to the west of Stolberg which looks prospective as well. Obviously what we need is a better market price environment, in order to take the risk out of drilling a potentially new oil pool, but that’s something we can do sometime in later 2016 or 2017— whenever the oil market comes back to whatever ‘normal’ is at that time.
NOTE: Part Two of Oil & Gas 360®’s exclusive interview with Mass Geremia will be published next week.