All photos courtesy of Michael Grant Edwards
OIL & GAS FINANCIAL JOURNAL: Venoco explores for and produces oil and natural gas both on-shore and offshore California. What advantages or disadvantages does being a California pure-play company bring to Venoco?
TIM MARQUEZ: Don, a lot of CEOs talk about California as a terrible place to operate, which it can be if you come in and expect to conduct operations exactly like you did in the mid-continent. While there are some big challenges operating in the Coastal Zone — including the three-mile wide "state waters" strip — and more complexity to operating in other parts of California, with the right, experienced personnel we don't think it's too onerous.
I started my career in California 30 years ago, started Venoco in 1992, and we've successfully operated here ever since. There is a perceived barrier-to-entry — kind of a "moat" around California — that we've used to build up a solid base of low-decline assets and a core holding in the oil-prone Monterey Shale.
It's also important to note that oil and gas plays in California are typically characterized by significant hydrocarbons in place. The multiple pay zones and long reserve lives that these reservoirs possess provide our engineers and geologists a great inventory of opportunities on our existing, producing leasehold. Our operating engineers and field personnel are focused on safe operations and finding new, cost-efficient ways to drive positive returns.
OGFJ: When Venoco went public four years ago, the company had operations in both California and Texas. Why did the company sell its Texas assets? Did Venoco retain any upside in those divestitures?
MARQUEZ: Like any successful company, management must ultimately decide where and how to allocate its capital and its resources. Subsequent to the sale of our largest Texas asset, the Hastings field, to Denbury Resources in February 2009, we were left with a dozen or so smaller fields. While we believed those fields were solid assets, we knew that our future efforts were going to be focused on the Monterey Shale. As such, we determined that it was the right time to monetize those assets and use the proceeds to fund development of the Monterey.
We retained a 22.3% reversionary working interest in the Hastings Field — our only asset outside of California. We understand that Denbury is on track to commence injecting CO2 into the field sometime around the end of this year, and we eagerly anticipate results from the CO2 flood. Because it's a reversionary interest (there will be several years before it pays out), it doesn't get much attention, but it's truly a hidden asset in our portfolio with almost 18 million barrels of booked, probable reserves. That said, we recognize that our core strengths and competitive advantages are in our California assets, so that's where we are focused.
OGFJ: How do the economics of producing in your California fields compare with other basins across the US?
MARQUEZ: We continue to believe that the economics in our plays compare favorably to many of the higher-profile plays around the US. Our experienced operations personnel have enabled us to drive down our drilling costs in the Sacramento Basin from around $1.2 to $1.4 million per well in 2008 to $800,000 to $900,000 today. Over time, we expect to replicate that drilling efficiency in the Monterey Shale. As a result, we think we'll see the economics from the Monterey eclipse the economics from other oil shale plays.
Here's an example of our economics: Our gas wells in the Sacramento Basin generate a 25% internal rate of return at $4.00 per MMBtu gas, and that's before our hedges. Our total well costs in the Sac Basin with two re-completions are about $875,000 with EURs of 0.7 bcf. With the hedges we have in place for this year and next, we can see rates of return from 50% to 75%. Now you can see why we believe California is a great place to operate.
In Southern California, where we've been operating for 16 years, our three largest oil fields, South Ellwood, Sockeye, and West Montalvo, are low-decline, legacy properties requiring little maintenance capital. These properties account for 85% of our approximately 8,000 boe/day with additional upside potential.
OGFJ: Estimated 2011 spending plans allocate at least $60 million, 30% of Venoco's total capital budget, toward natural gas projects. What drives your capital allocation decisions? Are there circumstances in which you would allocate a greater percentage of your capital toward oil projects?
MARQUEZ: Our capital allocation decisions are driven by returns. In today's environment, our oil projects are generating the highest rates of return. As a result, for 2011 we made the strategic decision to reallocate capital from Sac Basin natural gas projects to the oily Monterey Shale. We currently have 70% of our 2011 budget, or $140 million, allocated toward higher-return oil projects. Our producing legacy oil properties require little capital and generate consistently high-rates of return. We know and understand that gas price fundamentals will eventually improve, and when they do, we will likely resume a more active exploitation program in the Sac Basin.
OGFJ: Some people may not be aware of this, but historically, the Monterey Shale has been the largest producing oil play in the continental United States. Since Venoco is now focused more on the development of this resource, what has changed in recent years to make this play work and what areas of the shale is Venoco targeting?
Venoco's Platform Gail in Federal waters produces from several zones including two Monterey Shale intervals.
MARQUEZ: Without question, it's the processes, procedures, and technology that have revolutionized onshore development of the Monterey Shale. While most of the production from the Monterey Shale has been from conventional traps and natural fracture dominated fields, we believe that advances in horizontal drilling techniques, well completion technology, and 3-D seismic combined with new petrophysical models developed for mid-continent shale plays are what is going to unlock opportunities in the play.
OGFJ: You've recently started a horizontal drilling program in the Monterey Shale. What is the status of this drilling program and what results, if any, can you discuss?
MARQUEZ: The Monterey Shale program continues to be one of the most exciting and promising opportunities at Venoco, and for that matter, the entire industry. By year-end 2010, we will have drilled six vertical evaluation wells — our "science" wells — and four-to-five horizontal wells in the Monterey.
The first horizontal well we drilled was in the San Joaquin Valley to a total measured depth of 14,000 feet. While this particular lateral proved to be uneconomic because of a high water cut, we had good oil shows in that zone while drilling through it in the vertical evaluation well, so we are still interested in this prospect. We are completing our second horizontal well, in the Santa Maria Basin, and expect initial results in early November. The rig was moved to a nearby location in the Santa Maria Basin, and we spud our third horizontal well around the 20th of October. This is a very active time at Venoco, and we are all excited about the impact the Monterey Shale play can have on the company.
OGFJ: Have you been able to apply your offshore technical expertise to your onshore activities in the Monterey Shale?
MARQUEZ: Most definitely — the whole onshore Monterey Shale play evolved from producing the Monterey offshore and from work we were doing in a part of the Monterey column at our offshore Sockeye field. The main Monterey producing interval at Sockeye is called the M4. It is brittle rock in that zone that leads to natural fractures, which basically enhanced the permeability.
In a shallower part of the Monterey interval, we tested the M2 zone in vertical completions. The M2 is more ductile rock. It is less naturally fractured, and we saw 60- to 80-barrel IPs in the vertical tests. We drilled three horizontal wells about four years ago and saw IPs of 300, 600, and 800 barrels per day in unstimulated completions. Our geologists — who have decades of experience in California — said if you like the results from the M2 and want to find more of it, there is plenty of it onshore.
We feel fortunate to have been able to assemble a great team of geoscientists, engineers, and operations personnel with many years of experience in Monterey producing fields. We are definitely taking that understanding of the complexities of the Monterey and applying it to our development of our onshore Monterey Shale prospects.
OGFJ: The Monterey is estimated to be about 4,000 feet thick in some areas — multiple times thicker than the Bakken and other oil resource plays in North America. What drilling and completion techniques are you using to enhance recovery volumes?
MARQUEZ: Actually, in some parts of the San Joaquin, the Monterey may be twice that thick — 8,000 feet of gross interval — but in our target areas its average, gross thickness is between 1,000 to 2,000 feet. We think there are areas where a vertical well can have several hundred feet of net pay, but we think the best opportunities are going to be in identifying the top 2 or 3 net-pay intervals and laying in laterals. We believe the extra expense of a lateral will pay off through contact with thousands of feet of wellbore in those net-pay intervals. And unlike the expensive, 20- to 30-stage frac completions you hear about in other shale plays, we think our primary completion method will be big acid jobs to clean out drilling muds from the natural fracture systems.
OGFJ: What is Venoco's hedging strategy, and how does this portfolio benefit your increased exploration activities in California? What rates of returns are you seeing from your hedges?
MARQUEZ: Our hedging strategy is based on our years of experience in this business. We've lived through downturns and know the most important thing we can do to survive those downturns is protect the downside. We have been bearish on gas prices as we see plenty of gas supply resulting from the success of mid-continent gas plays and have focused on getting good floors for our anticipated gas volumes. We have solid hedges for the balance of 2010 and have 60 MMcf per day hedged at an average price of $5.43/Mcf for 2011 and have 37.3 MMcf per day at $6.16/Mcf in 2012.
|Venoco's Platform Holly where the Monterey Shale was 're-discovered' in 1969.|
We have more confidence on the oil side, but we still have floors on 7,000 barrels per day in 2011 at $50/barrel and we've layered in 3,000 barrels per day in 2012 at $60/barrel. We hedge primarily to protect our capital budget and maintain our financial flexibility. We don't want short-term price fluctuations to impact our long-term strategic investment plans.
OGFJ: Venoco has a seven-year inventory and 700 drilling locations across the Sacramento Basin in Northern California. Since this is primarily a natural gas play, what activities can the investment community expect in 2011? Will you be using cash flow from your gas operations to develop your oil portfolio?
MARQUEZ: You are correct about an abundance of locations in the Sac Basin. That 700-well inventory is based on 20-acre spacing, and we have been drilling some 10-acre spaced wells that appear to be working. We don't know that 10-acre spacing will work in all areas, but we do think we could add a substantial number of locations if we're able to prove up the 10s.
|Drilling rig on a horizontal well in the Santa Maria Basin.|
With gas prices where they are, where we think they'll be in the next few years, and our oil opportunities in Southern California, we plan on dialing back our spending in the Sacramento Basin. Our goal is to keep production rates fairly level year over year while reducing our capital expenditures in the basin. We'll do that by reducing drilling activity — 40 new wells in 2011 compared to our target of 100 in 2010 — and focusing more on re-completions. We expect to have positive cashflow from the Sac Basin in 2011, which we'll use to fund our development of the Monterey Shale.
We've told the investment community we are focused on advancing the Monterey Shale play. We are looking to drill 30 wells in the onshore Monterey, including 22 horizontal wells and 8 vertical evaluation wells. With those 8 evaluation wells we'll have drilled in about 15 of the 32 prospects our exploration team has identified so far. We expect to add to our leasehold in the Monterey Shale in 2011 and to complete the joint 3-D seismic shoot with Occidental Petroleum. We expect to have the processed 3-D data very soon from the first half of this 500--mile shoot (the largest 3-D seismic shoot ever in California) and the processed results from the final half in the second quarter of 2011.
OGFJ: Will you operate within cashflow during 2011? At what point does the Monterey Shale project become self-funding?
MARQUEZ: Based on our guidance and depending on actual commodity pricing during the year, we anticipate our $200 million capex budget will require additional funding. We've talked about the fact that we have heavily risked our production expectations from the onshore Monterey Shale play, so with better performance (especially early in 2011), we'd have less of a funding shortfall.
We are actively looking for joint venture partners on particular Monterey Shale prospects to reduce our capital outlays. We will also look at non-core assets we can monetize. We own pipelines in both Northern and Southern California that may be attractive to an MLP-type portfolio. We are very interested in the response at the Hastings field from Denbury's CO2 flood and the potential to move probable reserves over to the proved category. We think that could make our Hastings reversionary interest more valuable and more marketable. Once we have a better idea of other funding sources, we'll be able to judge the size of any gap and the need to look at using equity.
As for seeing positive cashflow from the onshore Monterey development, our unrisked model shows it could be as early as next year. Risking the model as heavily as we did this year would push that out by at least a year.
OGFJ: On October 11, Venoco announced an "at-the-market" offering. What prompted this offering and what will be the primary use of the proceeds?
MARQUEZ: First, we didn't make it very clear that it was an amendment to our existing shelf filing, and that we have not sold any shares. Selling equity is still our last choice — after JVs and non-core asset sales — to fund any shortfalls in 2011. My wife and I own about 29 million shares, so we understand how other shareholders view dilution. What we like about the ATM is it gives us optionality. If we can't fully fund a shortfall by other means or we project a smaller shortfall — say in the $10-20 million range — we can go use the ATM to complete a much smaller offering and get it done quickly.
As you know, we operate nearly 97% of our properties. We work hard to control capital spending and allocate capital based on objective analysis and rates of return. This is most clearly evidenced by our decision to redeploy capital from our natural gas projects in the Sacramento Basin to oil projects in the Monterey Shale. The operational control we maintain is important. It allows us to manage our spending plans and make decisions related to capital deployment initiatives or equity offerings.
That said, we have no current plans to draw down on the $75 million of equity. Instead, the capital resides on the shelf to further strengthen our financial flexibility. It's no secret that today's financial markets move quickly. At Venoco, we always want to make sure that we are well funded and prepared.
OGFJ: Thanks very much for your time, Tim, and best of luck to you. OGFJMore Oil & Gas Financial Journal Current Issue Articles
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