Temprano Energy Corporation and its predecessors have been in the oil and gas industry since September 2001.  Penntex Petroleum Corp.was formed in Austin, Texas out of the purchase of certain assets from Del Rio Energy Company of Victoria, Texas.  The original purchase from Del Rio was for 3 producing oil and gas wells, lease acreage held by production (HBP), and a 25-mile natural gas gathering system (pipeline) and all of its right of way in the Dime Box, Texas field.  Dime Box is located in Lee County, and borders Burleson County, Texas.

Penntex Petroleum Corporation, over the next 2 years, acquired additional acreage in the Dime Box Field.  PPC subsequently formed Penntex Drilling Fund I, LP (“Penntex LP”) for the purpose of drilling development wells on the acreage acquired by PPC.  In 2004 and 2005, PPC as general partner for the Fund, completed 4 producing wells in the field.  The four wells have been in continuous production since 2006.

Based upon the success of the Penntex LP, the founders acquired additional acreage in the Dime Box Field for the development of additional wells.  During 2007 and 2008, the founders created Nestex Exploration and Nestex Energy for the purpose of exploration and production with the additional acreage.  Nestex Development Funds I and II (“Nestex LPs I and II”) were subsequently created and funded and the partners drilled and completed 4 wells.  They have been in continuous production since 2009.

Temprano Energy Corporation was created by merging the assets of the parent of All Aboard Holdings Inc. and the LP units of Penntex LP, and Nestex LPs I and II.  The majority of holders approved the transaction on October 1, 2014 at which time TEC acquired all the assets of PPC, Penntex LP, Nestex LPs I and II.  The Company became the operator of 10 oil and gas wells in Dime Box, Texas, the owner of a 25-mile pipeline, and almost 1,000 net leased acres in the field.



Temprano Energy Corporation has identified four strategies for increasing production and acquiring additional reserves.  While the Company may elect to explore other technologies and methods for increasing production and reserve value, the strategies discussed below are what we believe to be the most viable, cost effective, and achievable in a relatively short period of time. 



TEC plans to use its existing acreage to drill additional wells.  Currently, the Company has 10 producing oil and gas wells located in the Dime Box Field in Lee County, Texas. The Company expects to save considerable resources and money by re-entering existing wells, inasmuch as it saves the cost of the vertical part of the well and the Company only pays the cost of the fracing and horizontal drilling.  It is not uncommon to have production increases of 300% or more over traditional vertical wells.



Horizontal or directional drilling is a method used by oil and gas exploration companies to increase production and hit targets that cannot be reached with a vertical well.  Most wells drilled for oil or gas are vertical wells, drilled straight down into the earth.  However, drilling at an angle other than vertical can obtain information, hit targets and stimulate reservoirs in ways that cannot be achieved with a vertical well.  In these cases, the ability to accurately steer the well in directions and angles that depart from the vertical is a valuable ability.  

When directional drilling is combined with hydraulic fracturing, some rock units, which were unproductive when drilled vertically, can become fantastic producers of oil or natural gas. Examples are the Marcellus Shale of the Appalachian basin and the Bakken Formation in North Dakota.  

Directional and horizontal drilling have been used to reach targets beneath adjacent lands, reduce the footprint of gas field development, increase the length of the "pay zone" in a well, deliberately intersect fractures, construct relief wells and install utility service beneath lands where excavation is impossible or extremely expensive. 

Below is a list of four reasons for drilling non-vertical wells. They are graphically illustrated by the four drawings below. 

A) Hit targets that cannot be reached by vertical drilling:

        Sometimes a reservoir is located under a city, park, subdivision, or other obstacle where drilling is impossible or difficult. This reservoir might still be tapped if the drilling pad is located on the edge of the obstacle and the well is drilled at an angle that will intersect the reservoir.

B) Drain a broad area from a single drilling pad.

        This method has been used to reduce the surface footprint of a drilling operation. In 2010, the University of Texas at Arlington was featured in the news for drilling 22 wells on a single drill pad that will drain natural gas from 1100 acres beneath the campus. Over a 25-year lifetime, the wells are expected to produce a total of 110 billion cubic feet of gas. This method significantly reduced the footprint of natural gas development within the campus area. 

C) Increase the length of the "pay zone" within the target rock unit.

        If a rock unit were 50 feet thick, a vertical well drilled through it would have a pay zone that is 50 feet in length. However if the well is turned and drilled horizontally through the rock unit for 5,000 feet, then that single well will have a pay zone that is 5,000 feet long - this will usually result in a significant productivity increase for the well. When combined with hydraulic fracturing, horizontal drilling can convert unproductive shales into fantastic reservoir rocks. 

D) Improve the productivity of wells in a fractured reservoir.

      Drilling in a direction that intersects a maximum number of fractures does this. The drilling direction will normally be at right angles to the dominant fracture direction.  Geothermal fields in granite bedrock usually get nearly all of their water exchange from fractures. Drilling at right angles to the dominant fracture direction will drive the well through a maximum number of fractures.



Improving recovery with steps to full-field EOR projects

The global average recovery factor for a typical oilfield is approximately 40%. This results in a large amount of identified oil left behind despite an existing production infrastructure. The need to improve the recovery factor and the accelerating of the associated production is the main driver behind the many EOR schemes in practice around the world.  The primary techniques for enhanced recovery are:

  • Water Flooding
  • Cyclic Gas injection
  • Alkali surfactant polymer (ASP) flood



Temprano’s basic strategy is to concentrate on known oil and gas fields where it believes significant reserves have remained undiscovered.  Most geologists and reservoir engineers believe up to 70% of the oil and gas in a particular field or formation remains in place.  Furthermore, in the case of certain structures, additional production zones may be encountered on the flanks of fields where previously there was little if any development.  Salt domes, prevalent through out the Gulf Coast region, are a classic example.  The East Texas Field, a series of salt domes that is still in production, was the largest oil-producing region in the world in the 1930s and has produced more oil than any other field in history.  Today it is still the second largest producing region in the United States behind Alaska.

Given the sharp drop in the price of oil in late 2014, many small independent exploration and production companies that have overleveraged their production to acquire leases have become sellers of production at deep discounts.  Temprano will look to take advantage of the distressed assets for sale.

In summary, Temprano has identified a four-pronged strategy to exploit the near-term price weakness as well as position itself when and if prices rebound in the coming years.  By purchasing production at deep discounts, the Company anticipates throwing off cash flow to acquire additional acreage and to internally fund its drilling program.