PQ reinvests excess cash-flow from Gulf Coast and GoM in Cotton Valley and Woodford Shale
Photos by Jay Faugot
OIL & GAS FINANCIAL JOURNAL: Charlie, can you tell our readers a little about your background and what prepared you for your current role at PetroQuest?
CHARLES GOODSON: I grew up with a parent who worked in the industry. My father was a geologist who worked for Exxon and several independents before eventually forming his own company with my brother, also a geologist. In fact, my grandfather, who I was named after, was involved in discovering the Golden Lane trend along the east coast of Mexico. In the 1930s, their assets were nationalized into Pemex by Mexico, and the company he worked for was merged into Stanolind, now a part of BP. Now, some 80 years later, things south of the border finally seem to be moving in the opposite direction.
My career began after earning a business degree from Louisiana Tech University and doing post graduate work at the University of Oklahoma. I worked with Mobil in their land department in the late 1970s. My next job with Callon Petroleum took me up the Mississippi River to Natchez where I was regional land manager. In a five-year stint with Callon, I was exposed to virtually every aspect of the E&P sector and the popular drilling fund era that abruptly came to an end as the Reagan administration implemented massive tax reduction legislation in the 1980s, thus ending their advantages.
We formed this company in 1985 along with several others and will celebrate our 30th anniversary this June. We started as a private prospect generation company, and as a way to survive a massive downturn in the industry in the late 1980s, we assembled a group of high net worth industry executives as partners. We shared a common belief that as the majors were exiting South Louisiana, it was an advantageous time for us to acquire and drill.
Some of those individuals continue to participate in projects we drill and ironically were in our largest discovery, Thunder Bayou, announced late last year. Today, as a NYSE-listed company, we have been involved in virtually every phase of capital formation along with projects in most basins in the Lower 48 and offshore, except for the deepwater. We have lots of experience managing through the highs and lows this industry continues to work through.
Over the years, I have been able to surround myself with great co-workers, who I listen to and go to for advice. Our independent board of directors is also very proactive. I believe in meeting challenges head on and taking definable risks when necessary. I also believe you have to be able to admit you are wrong sometimes. That is essential to a rewarding and successful profession in any industry.
OGFJ: PetroQuest has a 95% drilling success rate on more than 918 gross wells. Your current operational focus is the Gulf Coast, Gulf of Mexico, East Texas and North Louisiana interior Salt Basin, and the Woodford Shale. Why did you choose to focus on these areas?
GOODSON: Our strategy is to build, expand, and develop long-life resources using excess cash-flow generated from our Gulf Coast and GOM projects. We were initially drawn to the Gulf Coast due to the sheer size of the reservoirs and the tremendous cash-flow generated from these assets. We have deliberately maintained our focus and expertise in Gulf Coast assets over the years as a means to generate cash-flow for more predictable onshore growth projects. During the first nine months of 2014, our Gulf Coast assets produced approximately $40 million of free cash-flow. It's our belief that the East Texas Cotton Valley and the Oklahoma Woodford Shale are two of the best operating areas for reinvesting our excess cash-flow to generate the company's highest and best return. As of Dec. 31, 2013, about 80% of our proved reserves and 60% of our production were located in long-life basins. Also, access to services, excess takeaway capacity, and very supportive state and local agencies, along with an oil and gas friendly elective, make these areas desirable and support our long-term activity.
OGFJ: The plays you mention are traditionally gassy areas with a slight liquids component. Many operators have dropped their natural gas-weighted properties to drill for crude oil. Why is your approach different?
GOODSON: We tend to take a longer-term approach when it comes to evaluating commodity prices. There are a number of domestic, macro, and industry-specific developments we believe will positively impact natural gas prices in the future. As a result, we remain supportive on natural gas prices over the long term. That said, we worked hard to expose our company to liquids-rich basins so that we can responsibly allocate capital to high-return projects at any commodity price. For example, our Woodford production stream is about 49% liquids, which helped us grow the company's total liquids production by 139% from 2011 through the first half of 2014. We will continue to find and develop natural gas liquids-rich projects to generate cash-flow, but we still believe there is higher upside potential for natural gas prices. Since 2008, natural gas prices have declined while overall production in America has continued to grow. Currently, natural gas trades in a price band that equates to $20 to $30 per barrel equivalent. At these prices, natural gas will continue to compete favorably with all alternatives and will be a fuel of choice as demand for its usage expands.
OGFJ: You've recently been more public with your onshore Gulf Coast assets, reporting new company-maker discoveries. Why has the Gulf Coast area remained one of your premier assets?
GOODSON: Over the years, companies have abandoned plays like the Gulf Coast in pursuit of shale opportunities. The reality is every successful Gulf Coast well has the potential to be a significant cash-flow generator. We've drilled three wells at La Cantera and recently reported a new discovery at Thunder Bayou, which is another game-changer for us.
In March 2012, we announced the first discovery well. Initial production from the first La Cantera well on a gross daily basis was 36 MMcfe/d. Two subsequent wells were placed online with initial production rates of 52 MMcfe/d and 35 MMcfe/d. The total proved gross reserves associated with this project are approximately 100 bcfe and we believe that we will ultimately produce well north of the proved number. Our net revenue interest at La Cantera is 15%.
To date, La Cantera has produced more than 70 bcfe from the Cris R2 sand since its completion in March 2012 and has generated more than $60 million in field-level cash-flows net to PQ. With total finding and development costs of substantially less than $1.00 per Mcfe and IRRs in excess of 100%, we believe projects like La Cantera provide some of the best returns in North America.
To summarize our business approach to the Gulf Coast Basin, in 2003 as we began the company's expansion outside of this area, we made a conscious decision to support our very experienced staff and developed a realistic plan that would reinvest about 50% of the area's cash-flow and yet expect growth over a realistic time-frame. By using our extensive partner relationships to reduce exposure on the diverse project inventory our team continues to develop, we have continuously achieved those goals well beyond anyone's expectations. Also, by not using this area as our primary growth driver, we have been able to increase our success rate by allowing our team the time to de-risk every aspect of the generation process by using advancing technologies and ample time to work through this process.
OGFJ: Your Thunder Bayou well was a new discovery in Vermilion Parish, an exploration test two miles north of the company's 2012 La Cantera discovery. Tell us more about the Thunder Bayou discovery. What was the cost of the well? What positive effect will the discovery have on PetroQuest's production and cash-flow?
GOODSON: In December 2014, we announced our Thunder Bayou well encountered 490 gross (202 net) feet of pay in our primary Cris R2 objective. All of our early expectations are that Thunder Bayou is very similar in size and scale to La Cantera. Production is expected to commence during the second quarter of this year at a gross rate of between 25 MMcf/d and 30 MMcf/d plus liquids, which should have a substantial impact on our production and cash-flow profiles.
All-in costs at Thunder Bayou were approximately $25 million to drill the well with an additional $10 million for the processing facility. Our working interest is 50%, and we have a 37% net revenue interest in the well.
To give you an idea of how this may affect our cash-flows, our La Cantera project, which we believe could be comparable to Thunder Bayou, generated approximately $61 million since 2012 with a 15% net revenue interest. Using our Thunder Bayou net revenue interest of 37% the project well would have yielded over $150 million of cash flow over that same period.
OGFJ: Are these Gulf Coast wells economic at current strip prices?
GOODSON: These types of wells provide incredible returns at current prices. For a net cost of approximately $10 million, we exposed ourselves to over 80 bcfe of net unrisked reserve potential with finding and development costs substantially under $1.00, payout in less than one year, and a profitable project life of approximately 10 years.
OGFJ: You've also been very successful in the Woodford shale. Can you bring us up to date on how you've been able to reduce costs and increase well performance?
GOODSON: In the past, we've referred to our Woodford shale program as the company's premier onshore asset for two primary reasons. First, the diverse hydrocarbon opportunities within the trend are extremely attractive. A diverse hydrocarbon basin allows us to divert capital to the highest rate-of-return projects based on the commodity price landscape. Since 2013, our operational focus has shifted from the dry gas area of the Woodford to the North Relay field, our initial liquids-rich discovery, to the wet-gas area of the West Relay field.
The second reason is the effect our joint venture program has on our rates-of-return. Our joint venture covers about 100,000 acres, including our 30,000-acre liquids-rich West Relay field. Our rates-of-return at West Relay are enhanced because of the reduced capital expenditure commitments from our joint venture agreement, as well as the boost we receive from the high liquids component. PetroQuest currently pays 25% for a 50% interest in all wells drilled through May 2015. In JV terms, our EURs are averaging 4.6 bcfe with well costs of $4.0 million.
To give you an idea of the effect of the joint venture terms, in a $4.00 per Mcf natural gas environment, and $26.00 NGL prices, we are able to generate a 117% rate-of-return at West Relay. In return, PQ has not only dedicated its Arkoma cash flow, but also redirected its East Texas and Gulf Coast basin cash-flows to support the growth our JV partner desires. It has been a win-win relationship.
In addition, it's always been our focus to make great plays like this better. Since our development program began in the beginning of 2014, we have successfully drilled and completed 20 gross wells with significantly higher IP rates and a greater liquids component than our previous programs. For example, at North Relay, 31 of our wells had an average initial production rate of 4.6 MMcfe/d with a liquids cut of approximately 36%. Fast forward to today at West Relay, approximately 20 of our wells recorded average initial production rates of 6.4 MMcfe/d with a liquids cut of nearly 50%.
OGFJ: From 2003 to 2007, PQ drilled more than 60 vertical wells in the Cotton Valley right before the Haynesville shale boom. The Cotton Valley has re-emerged as one of the most exciting liquids-rich plays in the US. Walk us through the evolution of the Cotton Valley and how this play fits into your drilling portfolio.
GOODSON: The Cotton Valley stretches from East Texas across Northern Louisiana and is home to multi-Tcf fields such as Carthage. Like many other legacy oil and gas producing regions, the Cotton Valley emerged as a conventional, vertical play. We entered the East Texas portion of the Cotton Valley in 2003 through an acquisition and a joint venture with Chevron to develop 50,000 gross acres that at the time were largely undeveloped.
The early years of the Cotton Valley were difficult. The initial vertical wells that were being fracked were made economic because of higher natural gas prices and a Travis Peak zone that we dual completed along with the Cotton Valley. We drilled around 60 vertical wells with an average EUR of 0.7 bcfe from the Cotton Valley and a comparable EUR from the Travis Peak formation. We were about to implement a horizontal drilling program in 2008 to try and enhance the economics. Then, the Haynesville Shale hit, which dramatically reduced the availability of services for our Cotton Valley program and shortly after that, commodity prices pulled back in conjunction with financial market turmoil of 2009.
We then diversified into other regions and honed our skills in the Woodford shale, and by 2011, we had participated in almost 500 gross horizontal wells. This drilling and operating experience proved to be invaluable as we moved forward with the next stage of our exploration program. When natural gas prices started to rebound in early 2011, we transferred our horizontal drilling techniques and skills back to the Cotton Valley. The early vertical well programs didn't drain much of anything on our properties, so we decided to go horizontal. Internally, we estimated we'd see a 3x uplift in EUR from a horizontal well - but, we've seen a 12x uplift. To date we've drilled only 15 operated horizontal wells and have more than 200 horizontal well locations identified in the Cotton Valley.
OGFJ: You continue to announce Cotton Valley wells with production rates in excess of 10 MMcfe/d, and your EURs continue to grow. What's the key to drilling and completion success in the Cotton Valley?
GOODSON: Yes, the Horizontal Cotton Valley keeps outperforming our pre-drill expectations. Our independent third-party engineering firm recently endorsed an impressive average EUR of 9 bcfe per well for our five most recent horizontal Cotton Valley wells. Our horizontal Cotton Valley wells produce about 50 barrels of liquids per 1,000 Mcf of natural gas. Using a drill and complete cost of $6.2 million, 9 bcfe EUR and $4.00 gas, these wells generate an IRR of 60% with a 1.2 year payout.
During 2014, our average initial production rates were 11.9 MMcfe/d representing an increase of 89% from 2011 levels. These initial production rates on our recent wells greatly exceeded our internal estimates. Just as we've done in the Woodford, we are moving down the learning curve and quickly finding ways to reduce costs and enhance production and EURs.
We attribute the success to the hundreds of horizontal wells we drilled prior to the Cotton Valley horizontal program. We have become experts in staying in-zone. We always have someone watching the drill bit 24 hours a day instead of just turning the horizontal leg and checking back on the well every few days. Our ability to constantly monitor and stay in zone has really been our key to success in these thinner sands and shales.
Our completion design is fairly straightforward on our 4,000 to 5,000 foot standard laterals - we are completing these with an average of 10-12 plug and perf frac stages. We've been utilizing slickwater and find that around 225,000 pounds of premium white sand per stage is the ideal frac recipe.
OGFJ: Your presentation shows PQ is able to generate a 60% IRR on its Cotton Valley wells. Can you explain these economics and how you are able to generate these returns at low prices?
GOODSON: In a $4.00 per Mcf natural gas environment, PQ's horizontal Cotton Valley wells generate an IRR in excess of 60% with a payback period of 1.2 years. Currently, our well costs are averaging $6.2 million per well but it's early - we've only drilled 15 horizontal wells. We have a track record of reducing drilling costs and as we find ways to reduce drilling costs in the Cotton Valley, we believe these economics can only get better. Through improved D&C design, we believe we will be able to reduce our costs roughly 10% in 2015. Additionally, these production streams are very rich btu gas and some condensate. About 25% of the NGL stream is comprised of C4s and C5s. This high-value liquids component adds a significant uplift to our economics. The production stream from our Cotton Valley program averages around 70% natural gas and 30% liquids.
OGFJ: How will you make capital allocation decisions between these three top-notch assets?
GOODSON: We are rate-of-return driven and will allocate capital to areas where our company and shareholders receive the best return on their investment. During 2014, around 50% of our capital was spent in the Woodford. As I mentioned, the Woodford is a major focus for us and will continue to receive a large portion of our capital as long as rates of return are north of 100%. The remainder of our capital budget will be split between the Cotton Valley and the Gulf Coast programs. While we haven't issued 2015 guidance, we do not anticipate this allocation to drastically change, although our East Texas Cotton Valley team will most likely see a boost to its capital program.
OGFJ: Thank you for your time.