March 2012 ENErGY

Energy LawyersTransactionalallford, r. Bruce rba@bdplaw.com ............. 403-260-0247Barretto, Jeremy jbarretto@bdplaw.com .............. 403-260-0207campbell, q.c., harry S. hsc@bdplaw.com .............. 403-260-0281cuthbertson, q.c., John h. jhc@bdplaw.com .............. 403-260-0305Gilchrist, Mike mgilchrist@bdplaw.com .............. 403-260-0280houston, Mark T. mth@bdplaw.com .............. 403-260-0375Inch, Julie J. jinch@bdplaw.com .............. 403-806-7808Johnson, q.c., cal D. cdj@bdplaw.com .............. 403-260-0203Jones, candice J. cjj@bdplaw.com .............. 403-260-0109Money, J. Stuart jsm@bdplaw.com .............. 403-260-0312Pettie, q.c., alan T. atp@bdplaw.com .............. 403-260-0127Quesnel, alicia K. akq@bdplaw.com .............. 403-260-0233rogers, aaron M. arogers@bdplaw.com .............. 403-806-7806Saffery, hazel hsaffery@bdplaw.com .............. 403-260-0173Twa, q.c., allan r. art@bdplaw.com .............. 403-260-0221Weldon, ashley aweldon@bdplaw.com .............. 403-260-0125Wivcharuk, Jody L. jlw@bdplaw.com .............. 403-260-0129Wright, carolyn a. caw@bdplaw.com .............. 403-260-5721

RegulatoryBarretto, Jeremy jbarretto@bdplaw.com .............. 403-260-0207Miller, Keith F. kfm@bdplaw.com .............. 403-260-0153Quinton-campbell, Patricia pqc@bdplaw.com .............. 403-260-0308Saffery, hazel hsaffery@bdplaw.com .............. 403-260-0173Wright, carolyn a. caw@bdplaw.com .............. 403-260-5721

LitigationBatty, Trevor a. tbatty@bdplaw.com .............. 403-260-0263Beke, Paul a. pbeke@bdplaw.com .............. 403-260-0216Burron, Kevin S. kburron@bdplaw.com .............. 403-260-0189chernichen, q.c., Donald J. djc@bdplaw.com .............. 403-260-0101

crump, Barry r. brc@bdplaw.com .............. 403-260-0352Donaldson, Michael J. mjd@bdplaw.com .............. 403-260-0228haigh, q.c., David h. drh@bdplaw.com .............. 403-260-0135hannan, Kelly khannan@bdplaw.com .............. 403-260-0126hayes, Shannon shayes@bdplaw.com .............. 403-260-0237hyatt, Sheila shyatt@bdplaw.com .............. 403-260-0249Inch, Julie J. jinch@bdplaw.com .............. 403-806-7808McDonald, q.c., Daniel J. djm@bdplaw.com .............. 403-260-5724McDonald, Trevor r. trm@bdplaw.com .............. 403-260-0378McGillivray, q.c., Douglas a. dam@bdplaw.com .............. 403-260-0349Mills, Douglas G. dgm@bdplaw.com .............. 403-260-0226Murphy, James D. jdm@bdplaw.com .............. 403-260-0152Nishimura, Doug S. dsn@bdplaw.com .............. 403-260-0269Novinger Grant, Louise lng@bdplaw.com .............. 403-260-0163rojas, romeo a. rrojas@bdplaw.com .............. 403-260-0293Sharpe, Jeff E. jes@bdplaw.com .............. 403-260-0176Smyth, Stephen ssmyth@bdplaw.com .............. 403-260-0143Steele, richard F. rfs@bdplaw.com .............. 403-260-0051Strand, David h. dhs@bdplaw.com .............. 403-260-0259Strobl, Marika mstrobl@bdplaw.com .............. 403-260-0270Tallman, Scott stallman@bdplaw.com .............. 403-260-0273Teetaert, Melanie mteetaert@bdplaw.com .............. 403-260-0384Varzari, Jennifer K. jkv@bdplaw.com .............. 403-260-0286Wray, Shannon L. slw@bdplaw.com .............. 403-260-0245

Climate Change & Emmisions TradingGrout, David a. dag@bdplaw.com .............. 403-260-0326houston, Mark T. mth@bdplaw.com .............. 403-260-0375Jones, candice J. cjj@bdplaw.com .............. 403-260-0109Pettie, q.c., alan T. atp@bdplaw.com .............. 403-260-0127rogers, aaron M. arogers@bdplaw.com .............. 403-806-7806

Energy and other issues of On Record are available on our web site www.bdplaw.com

Energy, Editors-in-ChiefJohn h. cuthbertson, q.c.jhc@bdplaw.com403-260-0305

alicia K. Quesnelakq@bdplaw.com403-260-0233

Energy, Managing Editorrhonda G. Wishartrwishart@bdplaw.com403-260-0268

Contributing Writers and Researchers:aaron rogers, ashley Weldon, Jeremy Barretto, romeo rojas, Julie Inch, Justin Jensen, Jacob hoeppner, Brittney LaBranche and Brendan Sawatsky

ContactFor additional copies, address changes, or to suggest articles for future consideration, please contact the Managing Editor.

General NoticeOn record is published by BD&P to provide our clients with timely information as a value-added service. The articles contained here should not be considered as legal advice due to their general nature. Please contact the authors, or other members of our Energy team directly for more detailed information or specific professional advice.

If you would like any further information on any members of our team, such as a more detailed resume, please feel free to contact the team member or the Managing Editor. You may also refer to our website at www.bdplaw.com.

On Record Contents:

You Don’t really Expect Me To Pay This? The Problem of Stale Billing in the Energy Industry

Page 1

Inability to Drill and Force Majeure: Is The relief You Get The relief You Expect?

Page 3

Good Faith Negotiations – Does Such a Duty Exist?

Page 4

Deep Space – the carbon Sequestration Tenure regulation

Page 6

reducing the red Tape: recent changes to alberta Well Density controls

Page 8

2400, 525-8th avenue SW, calgary, alberta T2P 1G1Phone: 403-260-0100 Fax: 403-260-0332

www.bdplaw.com

1

The ScenarioHow often have you run across one of these scenarios in your everyday operational issues:

1. An Operator of a property, through its own internal audit procedures, discovers quite some time down the road (we are talking years here, not months) that it was calculating something incorrectly or missed billing for something. The Operator then sends a bill out to the joint owners looking for substantial sums of money long after the fact;

2. A service provider sends a bill out to the Operator for work or services done years before. The Operator in turn passes the bill on to the other joint owners; or

3. An Operator, or the owner of a royalty, determines that an error was made in paying royalties over an extended period of time and now seeks to rectify the error resulting in substantial sums owing by a joint owner.

The frequency with which this is happening has caused the local energy industry to focus on not only the practical business issues raised, but also the question of whether such invoices are in fact even legally collectable. From the practical side, certain industry participants have taken the position that regardless of whether the billing is in their favour or in favour

of others, if it extends beyond a certain period of time — as for instance, the end of the 24 month audit period allowed commonly in industry agreements for audits to be conducted in respect of a particular year, then they will neither bill for such matters, nor expect to pay for them.

The Legal Position However, what is the legal situation? As is often the case, the answer is not particularly straight forward, and Alberta courts may take a different approach than courts in other jurisdictions. The failure to pay an invoice is viewed as a breach of a contract. Under the Limitations Act (“the Act”), if a creditor does not commence a lawsuit within 2 years of the date it knew, or ought to have known, that the debt was due but had not been paid, then the debtor may use the Act as a defence and claim immunity from payment.

For older agreements, this limitation period is often extended by industry standard agreements which delay running the 2 year clock until after the audit time periods in the agreement have expired, or if there is no such audit provision, then for a period of 4 years after non-payment. In any event, the Act make provision for an ultimate “outside date” so that if one is more than 10 years out from the date that the “injury” occurred (i.e. non-payment), then nothing is collectible regardless of whether anyone had (or should have had) any knowledge of the claim or the non-payment.

YOU DON’T rEaLLY EXPEcT ME TO PaY ThIS?The Problem of Stale Billing in the Energy IndustryBy Romeo Rojas and Julie Inch

Ontario courts say that 2 things have to happen to start the clock for the running of the limitation period. First is the expiration of a reasonable period of time for the invoice to be delivered (to prevent the service provider from simply sitting on the invoice), while the second is the expiration of a reasonable time for the recipient of the invoice to actually pay the amount owing. The perhaps surprising result is that the time limitation does not begin to run on either the date on which the services were provided or the date on which the invoice itself was provided.

Piling two “reasonable periods of time” on top of each other (as in the Ontario test), certainly does not create any sort of “bright line” test of certainty. This Ontario approach looks to the practice between the parties as a guideline to determine these reasonable time frames.

The Alberta courts have not addressed the issue directly but, in comments in judgments on related issues, clearly have not adopted the Ontario approach as a general rule for all situations.

Where the Issues Can LeadAn Alberta royalty case illustrates some of the possibilities. Through the fault of neither party, both the royalty holder and the royalty payor

were unaware that, starting in 1988, royalties had become payable in respect of certain wells. The royalty payor first notified the royalty owner in May of 2002 that the wells were on production and royalties were payable. The royalty owner sued for royalty payments back to 1988. The Court took the position that each missed royalty payment gave rise to a separate claim with its own limitation period. Since neither party had been aware of the true facts, the Court allowed the action for all royalties other than those that were more than 10 years prior to the royalty owner commencing its claim in 2002. Had the royalty owner delayed commencing its action until June of 2006, it would also not likely have been able to collect for missed royalties from May, 2002 to approximately July or August of 2004.

Concluding ThoughtsThe calculation of the applicable limitation period in Alberta can be a tricky matter. One can not necessarily assume that an “old bill” is an “uncollectable bill”. The key to a more definitive answer is assembling the information relevant to answering the questions posed below and then consulting with legal counsel to confirm the result and whether the time to pay has passed.

2 ENERGY

The calculation of the applicable limitation period in alberta can be a tricky matter. One can not necessarily assume that an “old bill” is an “uncollectable bill”.

Practical GuidanceSo, what can we offer by way of guidance in Alberta for some of the situations outlined above? The following thoughts provide a starting point in examining such a limitation issue:

1. Look first to any written agreement between the parties. Does it address when invoices must be sent and when they become due? For instance, must invoices be provided within a certain time frame after the work is done?

Does the agreement contain language whereby the parties agree to extend the 2 year limitation period? The Limitations Act allows parties to lengthen (but not shorten) the time period.

Does the agreement contain a “24 month audit provision”? If it does, but the agreement does not extend the limitation period, then it is entirely possible that the limitation period for suing could expire before that audit process is even complete!

2. Determine whether there is an established practise between the parties in terms of how frequently invoicing occurs, and how quickly invoices are paid.

3. If a party receives a seemingly late billing, determine whether there are reasonable grounds for suggesting that the sender of the invoice has been “sitting on the bill” or whether there are unexplained delays in invoicing that are outside of the ordinary course of dealings with that party. If so, the limitation period may be a defence to payment of the invoice.

4. Determine whether the party providing the invoice can supply information as to the timing and circumstances of its own delivery of the invoice, or its determination of a prior royalty calculation error, so as to ascertain whether there have been inordinate delays.

5. Determine whether the agreement is one which is covered by the “Industry Standard Agreement” which extends limitation periods for agreements effective prior to February 15, 2001. If so, that would extend the limitation period to 2 years after the internal audit process provided by the agreement has been completed, or in any other case to 4 years from the non-payment.

6. Determine how many invoices were issued and when were they issued. Each invoice is its own claim and each could have its own limitation period.

7. Determine whether a partial payment has been made on the invoice or whether the debtor has acknowledged that the amount in the invoice is owing. If the partial payment or acknowledgement is made within the limitations period, it may restart the clock.

3

IntroductionRecent extreme weather events in the western provinces, such as the record snowfall and subsequent flooding experienced by south-eastern Saskatchewan in the spring of 2011 and increasingly unpredictable spring break-up temperatures, have generated a renewed focus on force majeure clauses by petroleum and natural gas lessees. In the face of such unavoidable circumstances, particularly where drilling is prevented close to the end of the primary term of a freehold lease, most lessees take it for granted that they can rely on the force majeure provisions of their lease to extend the period in which drilling must occur. But can they?

Background InformationForce majeure clauses are common contractual provisions that serve to allocate the risk of loss if performance becomes impossible or impracticable, especially as a result of an event or effect that the parties could not have anticipated or controlled. Most clauses are drafted to include both a general reference to causes beyond the control of the parties and a list of specific events that will be considered an event of force majeure. For example, the CAPL 1999 form of lease defines “Force Majeure” as follows:

“ Force Majeure” means any cause beyond the Lessee’s reasonable control and, without limitation, includes an act of God, strike, lockout or other industrial disturbance, act of any public enemy, war, blockade, riot, lightening, fire, storm, flood, explosion, unusually severe weather conditions and government restraints, including road bans, but shall not includes lack of finances.

Force majeure clauses may specifically exclude certain events, such as labour disputes or supply

chain disruptions, from the definition of force majeure. They can also impose obligations such as a notification requirement and a duty to mitigate the event of force majeure.

In most commercial contracts, the existence of an event of force majeure, as defined in the contract, is sufficient to satisfactorily relieve the affected party from further performance under the contract until force majeure has ceased to exist. In freehold petroleum and natural gas leases, however, the analysis is not quite so simple. The distinction between the existence or occurrence of a force majeure event and the relief provided by the terms of the lease can become much more significant than in most commercial contracts.

The ProblemMost freehold leases contain a standard habendum clause providing that the lease will continue in force for a specified period and for so long thereafter as production is obtained or deemed production is achieved. Canadian courts have definitively held that whether a lessee satisfies the habendum requirements to continue the lease is an option1. The problem is that most force majeure clauses are drafted in a manner that only provide for relief of a lessee’s obligations upon the occurrence of an event of force majeure. Under most freehold leases, however, the lessee has few actual obligations — the most notable being the obligations to pay rents and royalties and comply with offset well provisions.

As a result, a lessee that has delayed drilling until near the end of the primary term and is now having difficulties spudding a well faces an uphill battle. The lessee will likely be unable to rely on the force majeure provisions in its lease to extend the period in which it must drill to continue the lease.

Drafting ImplicationsSome lease forms, however, including the CAPL form of leases, have been drafted in a manner that appears intended to avoid this result. In the CAPL leases, the force majeure clause refers both to “obligations” and “operations”. The use of “operations” mirrors the habendum requirement to conduct “operations” in order to continue the lease. Thus, the force majeure clause contained in the CAPL leases purports to relieve the lessee from any need to conduct operations or fulfill its obligations under the lease upon the occurrence of an event of force majeure. However, no Canadian court has yet interpreted the application of this form of force majeure clause to prevent termination of the lease.

ConclusionForce majeure clauses in freehold petroleum and natural gas leases can be of limited value to prevent the automatic termination of a lease if they only relieve a lessee of its obligations under the lease. Broadening the language of the force majeure clause to refer specifically to the language used in the habendum of the lease may enable a lessee to rely on the force majeure clause to avoid the termination of a lease. As with most freehold lease issues, the precise wording of the force majeure definition and governing clause are paramount in determining what relief a lessee is entitled to when claiming force majeure under a freehold lease. As a result, lessees would be well advised to be wary of believing that they can rely on force majeure provisions to continue a freehold petroleum and natural gas lease.

Footnotes

1 Canadian Superior Oil of California Ltd. v. Kanstrup, [1965] S.C.R. 92.

Inability to Drill and Force Majeure: Is The Relief You Get The Relief You Expect? By Aaron Rogers and Ashley Weldon

4 ENERGY

Introduction – The General RuleAs the law in Canada currently stands, the general rule is that there is no cause of action against a party that fails to carry out contractual negotiations in good faith. This general rule has been adopted from English law where it has been stated that such a duty is “…inherently repugnant to the adversarial position of the parties involved in negotiations…” and that in order to negotiate effectively, a party must be able to “…threaten to withdraw from further negotiations or to withdraw in fact, in the hope that the opposite party may seek to reopen the negotiations by offering him improved terms.”1 Addressing the same issue, in Martel Building Ltd. v. Canada (“Martel”), the Supreme Court of Canada set out the following policy reasons for not imposing a good faith duty in the case of commercial relationships:2

• Commercial negotiation sometimes involve goals of achieving financial gain at the opposing party’s expense;

• Disclosure of one’s motives, final position or bottom line would defeat the essence of negotiation and hobble the marketplace;

•Such a duty would provide less incentive to perform adequate due diligence;

• Unless conduct amounts to misrepresentation, deceit, fraud, undue influence or economic duress, it is undesirable for the Courts to scrutinize pre-contractual conduct; and

• Given the number of negotiations that do not ultimately culminate in an agreement, recognizing such a duty would result in a flood of litigation.

Implied and Express Duties of Good Faith On several occasions, where negotiations have broken down and the parties have yet to form a contract or have not included an express duty of good faith negotiations in their agreement, the offended party has attempted to argue that the court ought to imply a duty to negotiate in good faith. This was the case in a 2003 British Columbia decision where a lessee of a gas station attempted to argue that the owner of the gas station was subject to an implied duty of good faith when negotiating a head lease that the owner held with Shell Canada. After reviewing the case law, the Court refused to imply such a term and noted that “…[w]hile the law in Canada recognizes the concept of good faith in matters of disclosure, it has not yet embraced that concept in terms of negotiations or bargaining.”3

Even where parties have attempted to protect themselves by inserting an express term into their contract mandating good faith negotiations, courts have been reluctant to uphold such provisions. This was the case in P.P. (Portage) Holdings Ltd. v. 346 Portage Avenue Inc.4 where the parties had entered into an easement agreement for an enclosed pedestrian corridor, which linked the their buildings. The easement agreement contained a term that required the parties to “…negotiate in good faith… in order to

settle on terms and conditions of a [new] lease….” prior to the expiry of the current lease. The Manitoba Court of Appeal began by highlighting one of the fundamental contract law rules that mere agreements to agree are unenforceable and an express agreement to negotiate in good faith was not a binding contract but only an agreement to agree and, therefore, could not be enforced.

Circumstances where a Duty of Good Faith is RecognizedNotwithstanding the general rule discussed above, in a few narrowly defined circumstances, Courts have recognized a duty to negotiate in good faith.

1. An example arises in cases involving a power imbalance between the contracting parties as was the case in the following 3 circumstances:

Employment Contracts

In Wallace v. United Grain Growers Ltd (c.o.b. Public Press)5, the Court indicated that employment contracts require a duty of good faith negotiations based upon the following factors:

• formation of the contract does not result from two parties with equal bargaining power;

• employees on the whole lack the information necessary to achieve more favourable contract provisions than those offered by the employer; and

• the power imbalance continues to affect other facets of the relationship after the contract has been entered into.

Franchisor-Franchisee RelationshipsThe power imbalance issue was later applied by the Ontario Court of Appeal in the context of a franchisor-franchisee relationship.6

Condominium Corporation and DeveloperThe Ontario Court of Appeal has also extended the good faith doctrine to the relationship of a condominium developer to the condominium corporation.7

Good Faith NegotiationsDoes Such a Duty Exist?By Jacob Hoeppner and Brittney LaBranche, Student-at-Law

2. Another circumstance where the courts have imposed a duty of good faith negotiations is in the situation where the parties have agreed, within the context of an otherwise complete and binding contract, to negotiate a specified term outside of the contract. The Court in Empress Towers Ltd. v. Bank of Nova Scotia 8, (“Empress”) upheld an obligation to negotiate in good faith a new rental rate upon renewal of the parties’ lease. The Court held this was not simply an agreement to agree, nor was the clause about the rent uncertain as it required the rent to be “the prevailing market rate”. The certainty of the remaining term was crucial to the finding of the good faith obligation. The same exception was commented upon in Mannpar Enterprises v. Canada9 (“Mannpar”) where a different conclusion was reached. Mannpar had a contract for the extraction of sand with a right to renew subject to renegotiating the royalty rate and an annual surface rental. The Crown was not prepared to renegotiate. Mannpar sued on the basis that the Crown repudiated its obligation to renew the lease and had a duty to exercise good faith by negotiating to see if an agreement could be reached. In this case, the Court held that there was no such duty as there was no language to provide an objective benchmark to measure, such as “fair value” or “market value”. These cases suggest that, once a court is satisfied that the contracting parties have surpassed the realms of a mere agreement to agree and have a binding contract, leaving only a term to negotiate that is capable of being measured objectively, a duty to negotiate in good faith may be recognized.

Changes to come…?Recently in Oz Optics Ltd. v. Timbercon Inc. (“Oz”)10, the Ontario Court of Appeal, while tempted, declined to extend the doctrine of good faith negotiation beyond the context of a contractual relationship in circumstances where other causes of actions already provided appropriate remedies. In the Oz case, a fibre-optic supplier had been seeking competitive bids from producers other than Oz, while advising Oz that they were the only bidder. Although the Court ultimately decided the appeal on the grounds of negligent misrepresentation, the Court extensively reviewed the state of the law regarding good faith negotiations, noting that despite considerable

discussion by the judiciary and legal academics, “it remains difficult to ascertain in what circumstances it will be applied.” The Court stated its temptation to extend the good faith doctrine to pre-contractual negotiations and discussed the strong argument that a good faith duty should be recognised where a bidder is unknowingly considered as a bid among many.

The Court of Appeal appears to be inviting future courts to consider expanding the scope of pre-contractual duties of good faith. The Supreme Court of Canada has also hinted that it will address this issue when the appropriate facts arise. In a 1989 decision,11 it was noted that the pre-contractual duty of good faith was worthy of legal protection and in the Martel decision, discussed above, it was stated that “whether or not negotiations are to be governed by the duty of good faith is a question for another time.”

ConclusionFor the various policy reasons outlined by Canada’s top court, a duty to negotiate in good faith is not generally recognized under Canadian law. This can be the case even in circumstances where parties have included an express term to negotiate with each other in good faith. Traditionally there are only limited circumstances where a Court will make an exception to this general rule. However, recent judicial commentary suggests change in the law of pre-contractual negotiations may be coming.

Footnotes

1 Walford v. Miles, [1992] A.C. 128 (H.L.).2 [2000] 2 S.C.R. 860.3 G.M. Pace Enterprises Inc. v. Tsai, [2003] B.C.J. No. 2063 (S.C.).4 [1999] M.J. No. 354 (Man. C.A.).5 [1997] 3 S.C.R. 701.6 Shelanu Inc. v. Print Three Franchising Corp., [2003] O.J. No. 1919 (C.A.).7 Peel Condominium Corp. No. 505 v. Cam-Valley Homes Ltd. (2001), 53 O.R. (3d) 1 (C.A.).8 [1990] 73 D.L.R. (4th) 400 (BCCA).9 [1999] BCJ No. 850 (BCCA).10 2011 ONCA 714.11 International Corona Resources Ltd. v. Lac Minerals Ltd., [1989] 2 S.C.R. 574.

5

6 ENERGY

Deep Space

ThE CaRBON SEquESTRaTION TENuRE REGuLaTIONBy Jeremy Barretto and Brendan Sawatsky, Summer Research Student

7

BackgroundThe Carbon Sequestration Tenure Regulation1

(“the Regulation”) introduced in April, 2011 sets up the process for companies to seek tenure rights for Carbon Capture and Sequestration (“CCS”) projects.

Sequestration rights permit companies to inject carbon into pore spaces within subsurface reservoirs. Unlike leases for petroleum and natural gas, carbon sequestration leases have a distinctly regulatory flavour; sequestration leases are non-transferrable and are obtained by way of application rather than through a competitive bid process. If a company does not comply with the requirements contained in the Regulation, it may lose or be denied sequestration rights.

The Regulation provides greater detail on evaluation, monitoring and tenure elements of CCS first introduced with the Carbon Capture and Storage Statutes Amendment Act2 (“Bill 24”). Bill 24 established Crown ownership of pore space, the general process to obtain sequestration rights and the assumption of long term liability for CCS by the Government of Alberta. Most CCS provisions are in Part 9 of the Mines and Minerals Act3. For a summary of Bill 24 refer to the December 2010 BD&P Energy On Record Newsletter.

There are two main steps in order to acquire the right to inject carbon dioxide for long term storage: (1) securing an evaluation permit; and (2) obtaining a carbon sequestration lease. There is also a process defined in the legislation for the closure of CCS operations and facilities.

Evaluation PermitsA Section 3 evaluation permit allows a company to determine if a particular site is suitable for carbon sequestration for five years. A permit holder has the right to drill wells into “deep subsurface reservoirs” within the location of the permit to determine its geological or geophysical suitability.

Deep subsurface reservoirs are defined in the Regulation as pore spaces within an underground formation that are at least one kilometre below the surface of the land and within the location of the permit or lease. The maximum area for an evaluation permit is 73 728 hectares (slightly less than eight townships).

Substances approved by the Energy Resources Conservation Board (the “Board”) may also be injected into the reservoir for evaluation purposes (rather than for large-scale sequestration).

In order to acquire an evaluation permit, companies must apply to the Minister with a $665 application fee, a rental rate of one dollar per hectare and a “monitoring, measurement and verification plan” (“MMV”). The MMV contains an analysis of whether the evaluation operations may likely interfere with mineral recovery. The Minister may allow one MMV to be submitted for a group of adjacent permits.

Sequestration LeaseThe Section 9 carbon sequestration lease provides the lessee the right to inject captured carbon dioxide into deep subsurface reservoirs within the lease location (in addition to all of the rights of the evaluation permit). A sequestration lease is non-transferrable and is obtained by application for an initial term of 15 years. A carbon sequestration lease or evaluation permit does not grant the holder rights to “win, work or recover” any minerals.

The application process for a sequestration lease follows the requirements and fees associated with an evaluation permit application. In addition, the applicant must provide evidence that the location is fit for carbon sequestration and must provide a closure plan. A closure plan describes the activities that the lessee will undertake to close down the sequestration operations and facilities.

The MMV submitted with the lease application requires more details of reservoir suitability than the evaluation permit application. The applicant must submit to the Board an analysis of whether the lease operations may interfere with mineral recovery based geological interpretations and calculations (pursuant to Board Directive 65).

A sequestration lease, or portions of it, may be renewed for further terms of 15 years. A lease holder must submit a renewal application to the Minister along with a valid MMV and closure plan. The Minister may approve the application subject to any conditions; there is no right of renewal. To renew a lease, the Minister must be satisfied that the lessee has the approval of the Board that the injected carbon will not interfere with the recovery or storage of oil or gas.4

Closure of Sequestration Operations and FacilitiesBill 24 established that the Crown will become the owner of the sequestered carbon and assume obligations of the lease holder after the issuance of a “closure certificate” under the Mines and Minerals Act.5 The closure certificate will be

issued by the Crown when the captured carbon is behaving in a stable and predictable manner with no significant risk of future leakage.

Section 19 of the Regulation requires that a closure plan contain advice and recommendations about the monitoring, measurement and verification activities that should be conducted after the closure certificate is issued. A closure plan also includes an evaluation of whether the injected carbon dioxide has behaved in a manner consistent with the geological interpretations and calculations previously submitted. Even though the lease term is 15 years, the MMV and closure plans must be reviewed every 3 years or when a lease is renewed. This ensures that the lessee continues to actively monitor the site and lowers the chance of sequestration activities interfering with mineral extraction.

To cover the long-term monitoring and liability costs, the Regulation states that the lessee must pay into the Post-closure Stewardship Fund, a fee per tonne of captured carbon injected into the sequestration lease site at a rate “established by the Minister”.

CommentThe Regulation provides greater detail on the CCS regulatory framework first introduced in Bill 24 and presents a regulatory framework focused on protecting mineral recovery interests. The MMV and closure plans should be diligently prepared and updated. Regulators can compare the actual effect of the sequestered carbon with the predicted effect from plans submitted by the lessee every three years. A lessee may not conduct sequestration operations unless it complies with an approved MMV plan.

A critique of the Regulation is that the sequestration permit or lease holder does not have an exclusive or preferential right to evaluate or inject carbon within the location of the permit or lease.6 This could deter companies from drilling evaluation wells if they lack certainty about obtaining preferential rights for deep storage reservoirs that they identify.

Footnotes

1 Alta Reg 68/2011.2 Bill 24, 3rd Sess, 27th Leg, Alberta, 2010.3 RSA 2000, c M-17.4 Oil and Gas Conservation Act, RSA 2000, c O-6 at Section 39(1.1)

5 RSA 2000, c M-17 at Section 120.6 Nigel Bankes, “Alberta’s CCS Disposition Scheme: the Carbon Sequestration Tenure Regulation” (9 May 2011) online: <http://ablawg.ca/>.

8 ENERGY

reducing the red Tape:recent changes to alberta Well Density controlsBy Justin Jensen*

Producers should be aware of four important changes:

Removal of Subsurface Well-Density Controls The amendments eliminated well density controls for all coal bed methane and all shale gas reservoirs throughout the province. Well density controls were also removed for all gas zones to the base of the Colorado Group in certain conventional gas zones in south-eastern Alberta which are more specifically described in Schedule 13A of the OGCR (“13A Lands”).

Baseline Well Densities IncreasedThe amendments changed the baseline well density for different substances in certain areas of the province. Baseline well density refers to the number of subsurface draining locations necessary to maximize oil or gas recovery from a specific resource pool or geological formation. The baseline well densities for all conventional gas reservoirs province-wide have been increased from one to two wells per resource pool per standard drilling spacing unit. The baseline well density for oil wells on a standard drilling spacing unit, however, continues to be one well per quarter section drilling spacing unit.

Baseline well density on 13A Lands has also been changed. When the target area is above the Mannville Group, there are no baseline well density controls for conventional gas wells. When the target is an oil pool in the Manville group, two wells per oil pool may be produced.

These increased baseline well densities will only apply to lands that are not subject to previous spacing approvals and the amendments do not affect the Department of Energy rules for royalty calculations and tenure administration.

Target Areas CentralizedAs a general rule, the subsurface target area for drainage locations is now located in the center of the drilling spacing unit. An exception to this general rule exists for 13A Lands where corner target, or off center target areas will be standard for gas reservoirs only. The dimensions of the centralized target area for a well depend on the substances that are to be produced from the well. The target area for drilling spacing units for production of oil from all zones in all areas of the province must be at least 100 meters from all boundaries of the drilling spacing unit. For gas wells, the target area must be 150 meters from all boundaries of the drilling spacing unit except for 13A Lands where the allowable corner target areas are to be 150 meters from both the south and west boundaries of the drilling spacing unit.

Deemed Drilling Spacing Units The ERCB has implemented deemed drilling spacing units for certain fractional tracts of land. Fractional tracts of land that represent 50% or more of a traditional drilling spacing unit (1 section for gas and ¼ section for oil) will be considered to be standalone drilling spacing units without any need for an application to the ERCB to reduce the size of a drilling spacing unit. The amendment also creates the ability for potential producers to join fractional areas that are less than 50%

In October of 2011 the alberta Energy resources conservation Board (the “ErcB”) announced amendments to the Oil and Gas Conservation Regulations (the “OGCR”). The amendments altered the existing well density framework for both conventional and unconventional oil and gas reservoirs in alberta. The overall intent of the amendment is to reduce complexity in the regulatory framework as it applies to well density. Well density refers to the number of wells the ErcB permits to be drilled in a set area and varies depending on the geographical location of the proposed well(s) as well as the target substance(s).

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reducing the red Tape:recent changes to alberta Well Density controlsBy Justin Jensen*

of a standard drilling spacing unit with adjacent drilling spacing units that are under common mineral ownership without having to make application to the ERCB.

Potential Implications • For the new well spacing rules to apply to existing special drilling

spacing units, application must made to the ERCB to rescind the existing special drilling spacing units, and replace with the new parameters for drilling spacing units.

• These amendments remove the necessity of making an application to reduce the size of a drilling spacing unit in situations where a qualifying deemed drilling spacing unit exists.

• Deemed drilling spacing units should reduce the necessity to pool interests on fractional tracts of land that represent 50% or more of a traditional spacing unit.

• The ERCB has stated that wells drilled on target in accordance with the former drilling spacing unit and target area requirements before October 6, 2011 will not be subject to an off-target penalty. However, wells drilled after October 6, 2011 should comply with the new regulations or risk being subject to penalties.

• Though these recent amendments alter subsurface reservoir development and simplify the regulatory environment for subsurface rights, they are not intended to impact the rights of landowners with regards to surface development. The regulatory framework and the rights of landowners with respect to surface facilities remain unchanged.

* Justin, formerly an associate at BD&P, is now employed with Alberta Justice.

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