Last week, Alberta Energy announced further details regarding the MRF2 and introduced two new strategic royalty programs meant to encourage E&P companies to develop emerging high-risk plays and enhance production from existing pools. They also announced the option of an early opt-in2 for the MRF for E&P companies based on certain application criteria as a means to get more familiar with the program prior to launch in 2017.
Significance of Changes
Royalties are a key component in the determination of value for year-end reserves, acquisitions and divestitures. As such, Sproule is committed to understanding the new royalty costs associated with hydrocarbon development in Alberta and clarifying them for E&P companies, investors and creditors.
The MRF will impact the values estimated by Sproule for year-end reporting effective December 31, 2016, and for anyone else valuing potential investment opportunities from this point forward. The need to quantify the impact of the MRF is critical and Sproule has presented earlier commentary3 and sensitivity analyses4 in a webinar5 hosted this Spring 2016.
Summary of Changes to MRF as of July 11, 2016
Natural Gas Maturity Threshold
As expected, the natural gas Maturity Threshold is 345.5 e3m3e/month (about 400 mcfe/day) which is equivalent to the previously announced Oil Maturity Threshold of 194 m3e/month (about 40 boe/day). This is consistent with the assumption that both major evaluation software packages have been using.
The quantity adjustment for gas in initiated at the Maturity Threshold, based on the following formula:
rq = (Q-345.5)*0.04937%
As production declines, the reduction due to quantity adjustment increases, as shown in the graph. The quantity adjustment can only reduce the royalty to a minimum rate of 5%.
Liquid to Gas Equivalent Conversion Factor
The liquid to gas equivalent conversion factor for the Maturity Threshold calculations remains the same as it is in the current Alberta Royalty Framework, again consistent with the assumptions made by both major evaluation software packages:
1 m3 of liquids = 1.7811 e3m3 of gas, or
1 bbl oil = 10 mcf of gas.
It remains unclear if the same volume conversion factor will be used to determine royalty volumes of the in-stream components (ISCs) of propane, butane, and pentane. Differences between actual plant yields and the 10:1 barrel of oil equivalency factor are material and can cause significant differences in the economic results for certain plays.
Total Proppant Placed Adjustment Formulas
Alberta Energy has introduced additional adjustments to the Drilling and Completion Cost Allowance – C* calculation by introducing the “equivalency factor” to the Total Proppant Placed (TPP) input variable. This equivalency factor is designed to help account for different completion costs where more expensive proppants or different materials are used to complete a well. Wells which are stimulated with a material other than sand, or using acid as a completion fluid, will have an equivalency factor applied to TPP based on the table below:
|Type of Completion||Equivalency Factor|
|Resin Coated Sand (tonnes)||1.5 x TPP|
|Ceramic (tonnes)||2.5 x TPP|
|Acid (cubic metres)||10 x (acid concentration) x TPP|
|Examples of acid completions|
|7.5% concentration||0.75 x TPP|
|15% concentration||1.5 x TPP|
|28% concentration||2.8 x TPP|
It is our opinion that this change could have significant positive effects on the economic results of emerging high-cost plays that require more sophisticated completion designs, such as the Duvernay Formation.
Change in the Definition of Total Lateral Length
Total Lateral Length (TLL) is one of the components used to calculate the Drilling and Completion Cost Allowance – C*.
In Alberta Energy’s FAQs released on April 22, 2016, the TLL had been defined as the well’s Measured Depth (MD) minus the well’s True Vertical Depth (TVD), both in metres:
TLL = TVD – MD, metres.
However, in the most recent Alberta Energy information release on July 11, 2016, TLL is defined as “the combined length of all laterals in the well” with no formula for calculations provided.
It remains unknown how the TLL will actually be calculated upon finalization of the MRF.
Summary of Strategic Programs under Alberta’s MRF
The two new royalty programs that are meant to encourage E&P companies to develop new plays and enhance production from the existing pools are called Emerging Resources Program and Enhanced Hydrocarbon Recovery Program, respectively.
Emerging Resources Program
This program with an effective date of January 1, 2017 is aimed to “encourage industry to open up new oil and gas resources in higher-risk and higher-cost areas that have large resource potential”.
The program will be project specific and will be defined by a certain geographic area, target formation, and set of wells and associated infrastructure. Up to 15% of the total projected well inventory will be eligible to receive the benefit of the program. The wells must be drilled within a 10 year period and the project cost allowance pool has another 5 years to be depleted. The projects must encompass at least 18 sections of land to a maximum of 144 sections of land and be forecast to achieve at least a 5,000 boe per day (50,000 mcfe per day) production rate.
The project cost allowance pool is a sum of the individual wells’ program specific cost allowance (C*ERP) which will replace the wells’ normal C*. The exact calculation of C*ERP has not been determined yet, but it will be higher than the normal C* as per the range below:
150% of C*<= C*ERP <=200% of C*.
Wells drilled at different times through the initial stages of exploration, testing and development will receive different C*ERP, such that wells drilled early in the process will receive a C*ERP higher than those drilled later as the project matures.
All eligible wells will pay a flat 5% royalty rate until their combined revenue equals the total project cost allowance pool.
Alberta Energy will be accepting applications for the Emerging Resources Program over the next eight years, starting January 1, 2017, based on the following eligibility criteria:
- Large resource potential;
- The project is high risk and high cost;
- Early stage of development;
- The project is not commercial and is unlikely to become commercial without this program;
- There is a net royalty benefit to Albertans.
While many of the details of the program are still yet to be released, Sproule welcomes an introduction of the Emerging Resources Program. We think that conceptually this program will encourage investment into the development of emerging high-risk/high-cost plays like the Duvernay Formation. Based on the size requirements of the project area and the expected production volumes, Sproule believes that larger companies will be able to benefit more from this program. However, a lack of details prevents us from making any quantitative assessments of the potential benefits to the industry at this time.
Enhanced Hydrocarbon Recovery Program
This program will replace the Enhanced Oil Recovery Program as of January 1, 2017 for the schemes that have been approved or amended on or after January 1, 2017. Alberta Energy defines enhanced recovery methods as those which “involve the injection of various materials into a reservoir in order to increase production from existing developments.”
The program will consist of two main components:
- Tertiary recovery methods, involving the injection of carbon dioxide, nitrogen, chemicals (excluding polymer) or other substances approved by the Minister; and
- Secondary recovery methods, involving the injection of water (including polymer) or gas.
Under both components, there will be a flat 5% royalty rate on all products produced from all wells belonging to an approved scheme for a maximum time length of 90 months. Once the benefit period expires, all wells will convert to regular MRF royalties. The benefit period will depend on the recovery methods used and the estimated incremental recovery of hydrocarbons.
For the secondary recovery methods, the benefit period will be determined on a case by case basis as part of a two-year pilot.
For the tertiary recovery methods, the benefit period will be determined based on the existing benefit schedule under the current Enhanced Oil Recovery Program with a 25% reduction “to better align with new royalty rates under the MRF.”
Any new production wells drilled after January 1, 2017 as part of the approved scheme will also qualify for the Drilling and Completion Cost Allowance (C*).
The Enhanced Hydrocarbon Recovery Program will be application based. There are five main eligibility criteria for a recovery scheme posted on Alberta Energy’s website:
- It has to receive technical approval from the Alberta Energy on or after January 1, 2017; already approved schemes or the schemes with applications approved prior to January 1, 2017 will fall under the existing Enhanced Oil Recovery program, unless approved amendments are being implemented to them;
- It has to involve the injection of water or other substances approved by the Minister;
- It has to produce more hydrocarbons from the pool than could be produced from the base recovery scheme for that pool;
- It has to demonstrate that costs are significantly greater than operating the base recovery scheme; and
- It has to provide a net royalty benefit to the Crown over the life of the scheme.
Also, the qualifying schemes involving the injection of water or gas must be located in a pool or a part of a pool where no such activities have previously occurred.
The current Enhanced Oil Recovery Program will accept applications until December 31, 2016, and the schemes approved under it will continue receiving this benefit until the royalty credit is fully used or until the program expires on December 31, 2026, whichever comes first.
Alberta Energy will review the program in two years to better align it with the MRF’s cost allowance approach.
Early MRF Opt-In Option for Certain Wells
On July 12, 2016, Alberta Energy announced that for certain wells requiring additional capital investment that would not be otherwise drilled, an early opt-in application for the MRF may be submitted prior to January 1, 2017. The application must be submitted in writing to the Executive Director of Royalty Operations between July 13, 2016 and December 31, 2016 and before the well is spud. The well has to be spudded between July 13, 2016 and December 31, 2016. Based on Alberta Energy’s response to Sproule’s inquiry, there is no specific prescription on what data is required from an applicant to prove that the well represents an additional capital investment or that it would not be otherwise drilled. Applicants are free to use any information they deem relevant in support of their application.
Things We Still Do Not Know
While Alberta Energy has provided additional details regarding the MRF, aspects of the royalty calculations still remain unclear or unknown. These include:
- What is the actual formula for calculating TLL? How will the length be determined for each lateral leg of the well?
- How will Alberta Energy determine product par prices? Will oil be split into four product types (light, medium, heavy, or extra-heavy) as in the current royalty regime? Currently, the major evaluation software packages allow for different assumptions regarding par prices and the resulting well economics can be materially different based on the different assumptions.
- How will the in-stream component (ISC) volumes of propane, butane and pentane be handled? Will the ISC be included in the C* depletion? Will the ISC be included in Post-C* royalty calculations? Will the ISC be included in the maturity threshold calculation? Will the same 10:1 boe ratio be used for the ISC in converting them to liquid volumes? Our investigation shows that different assumptions for each of these questions can cause materially different economic results for certain plays.
In addition to these, there are a multitude of unknowns with regard to the newly announced strategic programs.
While the royalty rate is a function of price, production, and hydrocarbon split, the MRF proves to be an extremely complicated system, with many different variables used to calculate it. Thus, it continues to be necessary to look at various opportunities under specific price scenarios in order to determine what effect the MRF has on overall value. While there are still many uncertainties regarding the MRF, we now have a clearer understanding of the formulas used in the new framework.
Some of the biggest unknowns relate to in-stream component natural gas liquids. We recommend additional investigation into the impact of these unknowns when making decisions on high liquid-yield gas plays.
The two new strategic royalty programs should boost investment into enhanced recovery methods and into the development of emerging high-risk/high-cost plays.
Finally, the early opt-in option for the MRF should give some operators an opportunity to “test-drive” the new royalty regime on actual wells so that they are able to get more comfortable entering the 2017 drilling season.
Disclaimer: This article has been prepared for informational purposes only and does not constitute advice or an opinion on any issue. The article was derived from the interpretation of public information obtained from various sources and is partially based on discussions with individuals involved with reserves evaluations. If you have questions or comments, or require additional details or advice about specific situations, please contact Sproule directly.